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, 2002
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
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BP p.l.c.
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(Exact name of Registrant as specified in its charter)
ENGLAND and WALES
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(Jurisdiction of incorporation or organization)
1 St James's Square
London
SW1Y 4PD
England
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(Address of principal executive offices)
Securities registered or to be registered pursuant to Section 12(b) of the Act.
Title of each class Name of each exchange
on which registered
Ordinary Shares of 25c each Chicago Stock Exchange*
New York Stock Exchange*
Pacific Exchange, Inc.*
-------------------------------- -----------------------------
*Not for trading, but only in connection
with the registration of American Depositary
Shares, pursuant to the requirements of the
Securities and Exchange Commission
Securities registered or to be registered pursuant to Section 12(g) of the Act.
None
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Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act.
None
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Indicate the number of outstanding shares of each of the issuer's classes
of capital or common stock as of the close of the period covered by the annual
report.
Ordinary Shares of 25c each 22,378,650,865
Cumulative First Preference Shares of(pound)1 each 7,232,838
Cumulative Second Preference Shares of(pound)1 each 5,473,414
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes x No
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Indicate by check mark which financial statement item the Registrant has
elected to follow.
Item 17 Item 18 x
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Page 1
TABLE OF CONTENTS
Page
Certain Definitions....................................... 3
Part I Item 1 Identity of Directors, Senior Management and Advisors..... 5
Item 2 Offer Statistics and Expected Timetable................... 5
Item 3 Key Information........................................... 5
Selected Financial Information....................... 5
Risk Factors......................................... 10
Forward Looking Statements........................... 11
Statements Regarding Competitive Position............ 11
Item 4 Information on the Company................................ 12
General.............................................. 12
Segmental Information................................ 17
Exploration and Production........................... 19
Gas, Power and Renewables............................ 40
Refining and Marketing............................... 44
Chemicals............................................ 53
Other Businesses and Corporate....................... 59
Regulation of the Group's Business................... 61
Environmental Protection............................. 62
Property, Plants and Equipment....................... 68
Organizational Structure............................ 69
Item 5 Operating and Financial Review and Prospects.............. 71
Group Operating Results.............................. 71
Liquidity and Capital Resources...................... 88
Critical Accounting Policies
and New Accounting Standards....................... 92
Item 6 Directors, Senior Management and Employees................ 100
Directors and Senior Management...................... 100
Compensation......................................... 103
Board Practices...................................... 116
Employees............................................ 121
Share Ownership...................................... 122
Item 7 Major Shareholders and Related Party Transactions......... 125
Major Shareholders................................... 125
Related Party Transactions........................... 125
Item 8 Financial Information..................................... 125
Consolidated Statements and Other
Financial Information.............................. 125
Significant Changes.................................. 126
Item 9 The Offer and Listing..................................... 126
Item 10 Additional Information.................................... 129
Memorandum and Articles of Association............... 129
Material Contracts................................... 133
Exchange Controls and Other Limitations
Affecting Security Holders......................... 133
Taxation............................................. 134
Documents on Display................................. 137
Item 11 Quantitative and Qualitative Disclosures
about Market Risk....................................... 138
Item 12 Description of Securities Other Than Equity Securities.... 146
Part II Item 13 Defaults, Dividend Arrearages and Delinquencies........... 147
Item 14 Material Modifications to the Rights of Security Holders
and Use of Proceeds..................................... 147
Item 15 Controls and Procedures................................... 147
Item 16 Reserved..................................................
Part III Item 17 Financial Statements...................................... 148
Item 18 Financial Statements...................................... 148
Item 19 Exhibits.................................................. 148
Page 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 natural gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing
natural forces and mechanisms of primary recovery are included as 'proved
developed reserves' only after testing by a pilot project or after the operation
of an installed programme has confirmed through production response that
increased recovery will be achieved.
'Proved undeveloped reserves' -- Reserves that are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively
major expenditure is required for recompletion. Reserves on undrilled acreage
are limited to those drilling units offsetting productive units that are
reasonably certain of production when drilled. Proved reserves for other
undrilled units are claimed only where it can be demonstrated with certainty
that there is continuity of production from the existing productive formation.
Under no circumstances are estimates of proved undeveloped reserves attributable
to acreage for which an application of fluid injection or other improved
recovery technique is contemplated, unless such techniques have been proved
effective by actual tests in the area and in the same reservoir.
Miscellaneous terms
'ADR' -- American Depositary Receipt.
'ADS' -- American Depositary Share.
'Amoco' -- The former Amoco Corporation and its subsidiaries.
'ARCO' -- Atlantic Richfield Company and its subsidiaries.
'Associated undertaking' -- An undertaking in which the BP Group has a
participating interest and over whose operating and financial policy the BP
Group exercises a significant influence (presumed to be the case where 20% or
more of the voting rights are held) and which is not a subsidiary undertaking.
'Barrel' -- 42 US gallons.
'Billion' -- 1,000,000,000.
'BP', 'BP Group' or the 'Group'-- BP p.l.c. and its subsidiaries.
'Burmah Castrol' -- Burmah Castrol plc and its subsidiaries.
'Cent' or 'c' -- One hundredth of the US dollar.
The `Company' -- BP p.l.c.
'Crude oil' or 'Oil' -- Crude oil, condensate and natural gas liquids.
'Dollar' or '$' -- The US dollar.
'FSA' -- Financial Services Authority.
'Gas' -- Natural Gas.
'LNG' -- Liquefied Natural Gas.
Page 3
'London Stock Exchange' or `LSE'-- London Stock Exchange Limited.
'LPG' -- Liquefied Petroleum Gas.
'MTBE' -- Methyl Tertiary Butyl Ether
'NGL' -- Natural Gas Liquid.
'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.
'OPEC'-- The Organization of Petroleum Exporting Countries.
'Ordinary Shares'-- Ordinary fully paid shares in BP p.l.c. of 25c each.
'Pence' or 'p' -- One hundredth of a pound.
'Pound', `sterling' or `(pound)' -- The pound sterling.
'Preference Shares' -- Cumulative First Preference Shares and Cumulative Second
Preference Shares in BP p.l.c. of (pound)1 each.
'Subsidiary undertaking' -- An undertaking in which the BP Group holds a
majority of the voting rights.
'Tonne' or 'metric ton' -- 2,204.6 pounds.
'Trillion' -- 1,000,000,000,000.
'UK'-- United Kingdom of Great Britain and Northern Ireland.
'UK GAAP' -- Generally Accepted Accounting Practice in the UK.
'Undertaking' -- A body corporate, partnership or an unincorporated association,
carrying on a trade or business.
'US' or 'USA' -- United States of America.
'US GAAP' -- Generally Accepted Accounting Principles in the USA.
'Vastar'-- Vastar Resources Inc. and its subsidiaries.
Page 4
PART I
ITEM 1 -- IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISORS
Not applicable.
ITEM 2 -- OFFER STATISTICS AND EXPECTED TIMETABLE
Not applicable.
ITEM 3 -- KEY INFORMATION
SELECTED FINANCIAL INFORMATION
Summary
This information has been extracted or derived from the audited financial
statements of the BP Group presented elsewhere herein or otherwise included with
BP p.l.c.'s Annual Reports on Form 20-F for the relevant years which have been
filed with the Securities and Exchange Commission, as reclassified to conform
with the accounting presentation adopted in this annual report. With effect from
January 1, 2002, BP has adopted Financial Reporting Standard No. 19 `Deferred
Tax' (FRS 19). Comparative information for 2001, 2000, 1999 and 1998 has been
restated to reflect the change in accounting policy.
Years ended December 31,
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2002 2001 2000 1999 1998
----- ----- ----- ----- -----
($ million except per share amounts)
UK GAAP
Income statement data
Turnover............................................. 180,186 175,389 161,826 101,180 83,732
Less: joint ventures................................. 1,465 1,171 13,764 17,614 15,428
------ ------ ------ ------ ------
Group turnover....................................... 178,721 174,218 148,062 83,566 68,304
Total replacement cost operating profit (a).......... 10,246 16,027 17,679 8,894 6,521
Replacement cost profit before
exceptional items (b).............................. 4,698 8,291 9,314 4,662 3,479
Historical cost profit for the year.................. 6,845 6,556 10,120 4,566 2,651
Per ordinary share (c): (cents)
Profit for the year:
Basic.............................................. 30.55 29.21 46.77 23.55 13.82
Diluted............................................ 30.41 29.04 46.46 23.42 13.76
Dividends (d)...................................... 24.00 22.00 20.50 20.00 19.75
Average number outstanding of 25 cents
ordinary shares (shares million)................ 22,397 22,436 21,638 19,386 19,192
Balance sheet data
Total assets......................................... 159,125 141,970 144,862 89,481 84,835
Net assets........................................... 70,047 65,759 66,152 38,092 37,693
Share capital........................................ 5,616 5,629 5,653 4,892 4,863
BP shareholders' interest............................ 69,409 65,161 65,584 37,031 36,621
Finance debt due after more than one year............ 11,922 12,327 14,772 9,644 9,641
Debt to borrowed and invested capital (e)............ 15% 16% 18% 20% 20%
Other data
Per ordinary share (c): (cents)
Replacement cost profit before
exceptional items................................ 20.97 36.95 41.15 24.05 18.14
Net cash inflow from operating activities (f)........ 19,342 22,409 20,416 10,290 9,586
Net cash outflow from capital expenditure
acquisitions and disposals......................... 10,983 11,604 6,207 5,142 6,520
Page 5
Years ended December 31,
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2002 2001 2000 1999 1998
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($ million except per share amounts)
US GAAP
Income statement data
Revenues............................................. 178,721 174,218 148,062 83,566 68,304
Profit for the year.................................. 8,397 4,164 10,183 4,596 2,826
Comprehensive income................................. 10,422 2,649 7,730 3,674 2,848
Profit per ordinary share (c): (cents)
Basic.............................................. 37.48 18.55 47.05 23.70 14.72
Diluted............................................ 37.30 18.44 46.74 23.56 14.66
Profit per American Depositary Share (c): (cents)
Basic.............................................. 224.88 111.30 282.30 142.20 88.32
Diluted............................................ 223.80 110.64 280.44 141.36 87.96
Balance sheet data
Total assets......................................... 164,090 145,990 151,966 90,262 85,458
BP shareholders' interest............................ 66,999 62,322 65,554 37,838 37,334
Other data
Net cash used in investing activities................ 11,083 11,685 6,326 4,922 6,861
Net cash used in financing activities................ 5,123 5,853 7,852 3,332 2,161
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(a) Operating profit is a UK GAAP measure of trading performance. It excludes
profits and losses on the sale of fixed assets and businesses or
termination of operations and businesses and fundamental restructuring
costs, interest expense and taxation.
BP determines operating profit on a replacement cost basis, which
eliminates the effect of inventory holding gains and losses. For the oil
and gas industry, the price of crude oil can vary significantly from period
to period; hence the value of crude oil (and products) also varies. As a
consequence, the amount that would be charged to cost of sales on a
first-in, first-out (FIFO) basis of inventory valuation would include the
effect of oil price fluctuations on oil and products inventories. BP
therefore charges cost of sales with the average cost of supplies incurred
during the period rather than the historical cost of supplies on a FIFO
basis. For this purpose, inventories at the beginning and end of the period
are valued at the average cost of supplies incurred during the period
rather than at their historical cost. These valuations are made quarterly
by each business unit, based on local oil and product price indices
applicable to their specific inventory holdings, following a methodology
that has been consistently applied by BP for many years. Operating profit
on the replacement cost basis and a derivative measure, that is, profit
adjusted for depreciation and amortization arising from the fixed asset
revaluation adjustment and goodwill consequent upon the ARCO and Burmah
Castrol acquisitions, and adjusted for special items (charges and credits
that are not classified as exceptional under UK GAAP), are used by BP
management as the primary measures of business unit trading performance and
BP management believes that these measures assist investors to assess BP's
trading performance from period to period.
Replacement cost is not a US GAAP measure. The major US oil companies apply
the last-in, first-out (LIFO) basis of inventory valuation. The LIFO basis
is not permitted under UK GAAP. The LIFO basis eliminates the effect of
price fluctuations on crude oil and product inventory except where an
inventory drawdown occurs in a period. BP management believes that where
inventory volumes remain constant or increase in a period, operating profit
on the LIFO basis will not differ materially from operating profit on BP's
replacement cost basis.
Page 6
Where an inventory drawdown occurs in a period, cost of sales on a LIFO
basis will be charged with the historical cost of the inventory drawn down,
whereas BP's replacement cost basis charges cost of sales at the average
cost of supplies for the period. To the extent that the historical cost on
the LIFO basis of the inventory drawn down is lower than the current cost
of supplies in the period, operating profit on the LIFO basis will be
greater than operating profit on BP's replacement cost basis. To the extent
that the historical cost on the LIFO basis of the inventory drawdown is
greater than the current cost of supplies in the period, operating profit
on the LIFO basis will be lower than operating profit on BP's replacement
cost basis.
(b) Replacement cost profit before exceptional items excludes profits and
losses on the sale of fixed assets and businesses and termination of
operations and fundamental restructuring costs, which are defined by UK
GAAP. This measure and a derivative measure, that is, profit adjusted for
depreciation and amortization arising from the fixed asset revaluation
adjustment and goodwill consequent upon the ARCO and Burmah Castrol
acquisitions, and adjusted for special items (charges and credits that are
not classified as exceptional under UK GAAP), are used by the BP board in
setting targets for and monitoring performance within the Group. BP's
management believes these indicators provide the most relevant and useful
measures for investors because they most accurately reflect trading
performance.
(c) With effect from October 4, 1999 BP split (or subdivided) its ordinary
share capital. As a result, the number of Ordinary Shares held at the close
of business on Friday October 1, 1999, doubled, and holders of ADSs
received a two-for-one stock split. Comparative figures for 1998 have been
changed accordingly.
(d) BP dividends per share represent historical dividends per share paid by The
British Petroleum Company p.l.c., for 1998.
(e) Finance debt due after more than one year, compared with such debt plus BP
and minority shareholders' interests.
(f) The net cash inflows from operating activities are presented in accordance
with the requirements of Financial Reporting Standard No. 1 (Revised 1996)
issued by the UK Accounting Standards Board. For a cash flow statement
prepared on a US GAAP basis see Item 18 -- Financial Statements -- Note 50.
(g) The Group adopted Financial Reporting Standard No. 12 `Provisions,
Contingent Liabilities and Contingent Assets' with effect from January 1,
1999. Comparative figures for 1998 have been changed accordingly.
Page 7
Exchange Rates
The following table sets forth, for the periods and dates indicated,
certain information concerning the Noon Buying Rate for the pound in New York
City for cable transfers in pounds as certified for customs purposes by the
Federal Reserve Bank of New York. This is expressed in dollars per (pound)1.
At period end Average (a) High Low
------------- ------- ----- -----
Year ended December 31,
1998........................................ 1.66 1.66 1.72 1.61
1999 ....................................... 1.62 1.61 1.68 1.55
2000 ....................................... 1.50 1.51 1.65 1.40
2001........................................ 1.45 1.44 1.65 1.40
2002........................................ 1.61 1.50 1.61 1.41
Month of
September 2002.............................. 1.57 1.56 1.57 1.53
October 2002................................ 1.56 1.56 1.57 1.54
November 2002............................... 1.56 1.57 1.59 1.54
December 2002............................... 1.61 1.59 1.60 1.56
January 2003................................ 1.64 1.62 1.65 1.60
February 2003............................... 1.57 1.61 1.65 1.57
March 2003 (through March 19)............... 1.56 1.59 1.61 1.56
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(a) The average of the Noon Buying Rates on the last day of each month during
the calendar year or, in the case of monthly averages, the average of all
days in the month.
(b) The Noon Buying Rate on March 19, 2003 was $1.56 = (pound)1.
Dividends
BP has paid dividends on its Ordinary Shares in each year since 1917. In
2000 and thereafter, dividends were, and are expected to continue to be, paid
quarterly in March, June, September and December.
At least until December 31, 2003, BP will announce dividends for Ordinary
Shares in US dollars and state an equivalent pounds sterling dividend. Dividends
on Ordinary Shares will be paid in pounds sterling and on BP ADSs in US dollars.
Prior to the fourth quarterly dividend of 1998 The British Petroleum Company
p.l.c. announced dividends in sterling. Foreign exchange rates may affect
dividends paid.
The following table shows dividends announced by the Company per ADS for
each of the past five years, together with the `refund' but before deduction of
withholding taxes as described in Item 10 -- Additional Information - Taxation.
Refund means an amount equal to the tax credit available to individual
shareholders resident in the UK in respect of such dividend, less a withholding
tax equal to 15% (but limited to the amount of the tax credit) of the aggregate
of such tax credit and such dividend. Dividends have been translated from pounds
per ADS up to and including the third quarterly dividend for 1998, and from
dollars per ADS for the fourth quarterly dividend of 1998 and thereafter, at an
exchange rate determined in London on the business day last preceding the day
when the directors announced their intention to pay the quarterly dividends for
those years.
Page 8
Quarterly
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Dividends per American Depositary Share (a) First Second Third Fourth Total
------ ------- ------ ------ ------
1998................................ UK pence 21.5 22.5 22.5 23.0 89.5
US cents 36.0 36.5 37.5 33.4 143.4
Can. cents 51.4 55.3 57.8 50.0 214.5
1999................................ UK pence 20.5 20.8 20.2 20.8 82.3
US cents 33.3 33.3 33.3 33.4 133.3
Can. cents 48.7 50.1 48.6 48.5 195.9
2000................................ UK pence 21.5 22.3 24.0 24.1 91.9
US cents 33.3 33.3 35.0 35.0 136.6
Can. cents 49.7 49.8 53.6 53.2 206.3
2001................................ UK pence 24.4 26.1 25.4 27.0 102.9
US cents 35.0 36.7 36.7 38.3 146.7
Can. cents 53.7 56.0 58.5 61.0 229.2
2002................................ UK pence 27.0 25.8 26.0 25.4 104.2
US cents 38.3 40.0 40.0 41.7 160.0
Can. cents 60.1 63.0 62.3 63.8 249.2
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(a) With effect from October 4, 1999, BP split (or subdivided) its ordinary
share capital. As a result, the number of BP ordinary shares held at the
close of business on Friday October 1, 1999, doubled, and holders of ADSs
received a two-for-one stock split. Comparative figures for 1998 have been
changed 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 BP ordinary shares can elect to
reinvest the net cash dividend in shares purchased on the London Stock Exchange.
This plan is not available to any person resident in the USA or Canada, or in
any jurisdiction outside the UK where such an offer requires compliance by the
Company with any governmental or regulatory procedures or any similar
formalities.
A dividend reinvestment plan is, however, available for holders of ADSs
through JPMorgan Chase Bank.
Future dividends will be dependent upon future earnings, the financial
condition of the Group, the Risk Factors set out below, and other matters which
may affect the business of the Group set out in Item 5 -- Operating and
Financial Review and Prospects.
Page 9
RISK FACTORS
There is strong competition, both within the oil industry and with other
industries, in supplying the fuel needs of commerce, industry and the home.
The oil industry is particularly subject to regulation and intervention by
governments throughout the world in such matters as the award of exploration and
production interests, the imposition of specific drilling obligations,
environmental protection controls, control over the development and
decommissioning of a field (including restrictions on production) and, possibly,
nationalization, expropriation or cancellation of contract rights.
The oil industry is also subject to the payment of royalties and taxation,
which tend to be high compared with those payable in respect of other commercial
activities.
Investment and business activities in emerging markets present a higher
degree of business risk due to volatile economic conditions, less developed and
predictable legal systems, political instability, local security concerns and
the increased possibility of civil strife, war and various types of adverse
governmental action.
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. Operations are subject to delays, curtailment or
suspension due to adverse weather conditions or natural disasters.
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.
Natural gas prices are subject to regional supply and demand. Prices can
fluctuate significantly.
Refining profitability can be volatile with both oversupply and periodic
supply tightness in various regional markets.
The marketing of petroleum and related products, especially to retail
customers, can be affected by intense competition and general economic
conditions.
Crude oil prices are generally set in dollars while sales of refined
products may be in a variety of currencies. Fluctuation in exchange rates can
therefore give rise to foreign exchange exposures.
Sectors of the chemicals industry are also subject to fluctuations in
supply and demand within the chemicals market, with consequent effect on prices
and profitability, and to governmental regulation and intervention in such
matters as safety and environmental controls.
In addition to the adverse effect on revenues, margins and profitability
from any future fall in oil and natural gas prices, a prolonged period of low
prices or other indicators would lead to a review for impairment of the Group's
oil and natural gas properties. This review would reflect management's view of
long-term oil and natural gas prices. Such a review could result in a charge for
impairment which could have a significant effect on the Group's results of
operations in the period in which it occurs.
Page 10
FORWARD LOOKING STATEMENTS
In order to utilize the 'Safe Harbor' provisions of the United States
Private Securities Litigation Reform Act of 1995, BP is providing the following
cautionary statement. This document contains certain forward-looking statements
with respect to the financial condition, results of operations and business of
BP and certain of the plans and objectives of BP with respect to these items.
These statements may generally, but not always, be identified by the use of
words such as 'will', 'expects', 'is expected to', 'should', 'may', 'is likely
to', 'intends', 'believes' or similar expressions. In particular, among other
statements, (i) certain statements in Item 4 -- Information on the Company and
Item 5 -- Operating and Financial Review and Prospects with regard to management
aims and objectives, planned expansion, investment or other projects, expected
or targeted hydrocarbon production volume, capacity or rate, the date or period
in which production is scheduled or expected to come on stream or a project or
action is scheduled or expected to be completed, (ii) the statements in Item 4
-- Information on the Company -- Strategy and Financial Targets with respect to
the Group's ratio of net debt to net debt plus equity, dividend payments, the
manner in which we use cash surpluses, the target to reduce the cost structure
of the Group, hydrocarbon production growth, targeted performance improvements
and effect on pre tax results, and levels of annual investment, and (iii) the
statements in Item 5 -- Operating and Financial Review and Prospects including
the statements under 'Outlook' with regard to trends in the trading environment,
the outlook for economic recovery, oil and gas prices and realizations,
refining, marketing and chemicals margins, inventory and product inventory
levels, supply capacity, profitability, results of operation, working capital,
liquidity or financial position are all forward-looking in nature. By their
nature, forward-looking statements involve risk and uncertainty because they
relate to events and depend on circumstances that will occur in the future and
are outside the control of BP. Actual results may differ materially from those
expressed in such statements, depending on a variety of factors, including the
specific factors identified in the discussions accompanying such forward-looking
statements; the timing of bringing new fields on stream; future levels of
industry product supply, demand and pricing; operational problems; general
economic conditions; political stability and economic growth in relevant areas
of the world; changes in governmental regulation; exchange rate fluctuations;
development and use of new technology and successful partnering; the actions of
competitors; natural disasters and other changes to business conditions;
prolonged adverse weather conditions; wars and acts of terrorism or sabotage;
and other factors discussed elsewhere in this report. In addition to factors set
forth elsewhere in this report, the factors set forth above are important
factors, although not exhaustive, that may cause actual results and developments
to differ materially from those expressed or implied by these forward-looking
statements.
STATEMENTS REGARDING COMPETITIVE POSITION
Statements made in Item 4 -- Information on the Company, referring to BP's
competitive position are based on the Company's belief, and in some cases rely
on a range of sources, including investment analysts' reports, independent
market studies and BP's internal assessments of market share based on publicly
available information about the financial results and performance of market
participants.
Page 11
ITEM 4 -- INFORMATION ON THE COMPANY
GENERAL
Unless otherwise indicated, information in this Item reflects 100% of the
assets and operations of the Company and its subsidiaries which were
consolidated at the date or for the periods indicated, including minority
interests. Also, unless otherwise indicated, figures for business turnover
include sales between BP businesses.
BP was created on December 31, 1998 by the merger of Amoco Corporation of
the USA and The British Petroleum Company p.l.c. of the UK. Following this
merger, Amoco Corporation became a wholly owned subsidiary of The British
Petroleum Company p.l.c. and was renamed BP Amoco Corporation, and The British
Petroleum Company p.l.c. was renamed BP Amoco p.l.c. Amoco Corporation was
incorporated in Indiana, USA, in 1889 and The British Petroleum Company p.l.c.
was incorporated in 1909 in England. On April 14, 2000, we acquired the Atlantic
Richfield Company (ARCO) and on July 7, 2000, we completed our successful tender
offer for Burmah Castrol plc of England. To signify the single entity that has
successfully been created through these combinations, the name of the company
was changed to BP p.l.c. with effect from May 1, 2001.
BP is one of the world's leading oil companies on the basis of market
capitalization and proved reserves. Our worldwide headquarters is located in
London, UK. Our registered address is:
BP p.l.c.
1 St James's Square
London SW1Y 4PD
United Kingdom
Tel: +44(0)20 7496 4000
Internet address: www.bp.com
Business Overview and Strategy
Our main businesses are Exploration and Production; Gas, Power and
Renewables; Refining and Marketing; and Chemicals. Exploration and Production's
activities include oil and natural gas exploration and field development and
production (upstream activities), together with pipeline transportation and
natural gas processing (midstream activities). Gas, Power and Renewables
activities include marketing and trading of natural gas, NGL, new market
development, LNG and solar and renewables. 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 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. Currently, more than 70% of the
Group's capital is invested in Organization for Economic Cooperation and
Development (OECD) countries with just under one half of our fixed assets
located in the USA, and around one third located in the UK and the Rest of
Europe.
Our strategy is to create value from a distinctive set of opportunities,
biased towards the upstream, through a disciplined approach to investment within
our established financial framework. Consistent with this strategy, and based on
a thorough review of our assets and opportunities, we intend to increase our
investment, excluding acquisitions, to $14 billion to $14.5 billion in 2003,
focusing on creating five material new upstream profit centres, while divesting
$3 billion to $6 billion. We expect our annual investment level, excluding
acquisitions, to move toward the $12 billion to $13 billion range by 2005.
The information disclosed above for 2003 and beyond are forward looking
statements and as such are subject to numerous risks and uncertainties that may
cause actual results to differ as described under Item 3 -- Risk Factors and
Item 3 -- Forward Looking Statements.
Page 12
We believe that BP has a strong portfolio of assets in each of its four
main businesses:
-- In Exploration and Production we have upstream interests in 28
countries. In addition to our drive to maximize the value of our
existing portfolio we are creating five new profit centres in the
Deepwater Gulf of Mexico, Trinidad, Angola, Azerbaijan, and Asia
Pacific LNG in which we have competitive advantage and which provide
the foundation for volume growth and improved margins in the future.
We also have significant midstream activities to support our upstream
interests.
-- In Gas, Power and Renewables, we have established growing marketing
and trading businesses in North America (USA and Canada), the UK and
Europe. Our marketing and trading activities include natural gas, LNG,
NGL and power. Our international gas monetization activities are
focused on growing gas markets including the USA, Canada, Spain and
many of the emerging markets of the Asia Pacific region, notably
China. We are involved in power projects in the USA, UK and Spain.
Effective January 1, 2001, BP's North American NGL business was
transferred from Refining and Marketing to Gas and Power. On January
1, 2002, the solar, renewables and alternative fuels business
activities were transferred to the Gas and Power business from Other
Businesses and Corporate. To reflect this transfer, Gas and Power has
been renamed Gas, Power and Renewables from the same date.
-- In Refining and Marketing we have a strong presence in the USA. We
market under the Amoco and BP brands in the Midwest, East, and
Southeast, and under the ARCO brand on the West Coast. In Europe we
have a strong retail position and increased our presence in 2000 by
buying out ExxonMobil's interest in the BP/Mobil European fuels
business and in 2002 by acquiring Veba Oil (Veba). The Veba
transaction expanded our refining position in Germany and our
marketing position in Germany and Central Europe. Veba markets
gasoline under the Aral brand, which is now our principal retail brand
in Germany and in the Czech Republic. In 2000, we purchased Burmah
Castrol, which significantly increased our lubricants activities
throughout the world. In addition we have established or are growing
businesses elsewhere in the world under the BP brand.
-- In Chemicals, we are the world's third largest petrochemical company,
by capacity, with strong manufacturing and marketing bases in the USA
and Europe. We continue to grow in the Asia Pacific region, where we
already have interests in a number of production facilities. Our
portfolio is focused on seven core products. We have leading
technology in each of these products -- purified terephthalic acid
(PTA), acetic acid, acrylonitrile, paraxylene (PX), high density
polyethylene (HDPE), polypropylene, ethylene. During 2002, we
strengthened our market positions through the Veba acquisition whilst
also building new and expanding existing capacity.
The combination of BP and ARCO was completed on April 18, 2000. The
combination excluded ARCO's Alaskan businesses, which were sold to Phillips
Petroleum Company (Phillips) for approximately $6.8 billion cash. The
combination has been accounted for as an acquisition under UK GAAP and as a
purchase under US GAAP. The results of ARCO have been included with effect from
April 14, 2000, the day following the approval by the US Federal Trade
Commission of the acquisition. ARCO stockholders received for each share of ARCO
common stock held as of April 17, 2000, 9.84 Ordinary Shares.
BP acquired Burmah Castrol of the UK on July 7, 2000, for $4.8 billion
through a cash offer to shareholders of (pound)16.75 per share.
Page 13
In 2000, BP and ExxonMobil dissolved the BP/Mobil European joint venture in
response to the conditions of the European Commission's authorization of the
Exxon and Mobil merger. BP purchased ExxonMobil's 30% interest in the fuels
business for $1.5 billion with effect from August 1, 2000. In addition, the two
companies divided the assets of the lubricants business broadly in line with
their equity stakes (Mobil 51%, BP 49%). This dissolution was substantially
completed in 2000, thus increasing BP's share of all European markets where the
fuels joint venture was active.
On September 15, 2000, we acquired through ARCO the common stock of Vastar
held by minority shareholders at a price of $83 per share for a total
consideration of $1.6 billion. Vastar became a wholly owned subsidiary of the
Company.
During 2000 BP made two strategic investments in China, one of the world's
fastest growing economies. BP invested $416 million in the China Petroleum and
Chemical Corporation (Sinopec) and $578 million in PetroChina in the initial
public offerings of both companies. BP has an interest of around 2% in each
company. Separately, BP has formed a joint venture with PetroChina in Guangdong
province which had 320 service stations at the end of 2002, and has agreed to
form a joint venture with Sinopec to acquire, revamp or build service stations
in the Zhehang Province. PetroChina and Sinopec are two of China's major
companies in the oil and chemicals businesses.
With effect from February 1, 2002, BP acquired a majority stake in Veba Oil
from E.ON. Veba owns Aral, Germany's biggest fuels retailer. BP paid E.ON $1.6
billion in cash and assumed some $1.0 billion of debt in return for 51% and
operational control of Veba. Under the terms of the agreement, E.ON had the
option to require BP to buy the remaining 49% of Veba.
On June 30, 2002, BP purchased the remaining 49% of Veba Oil from E.ON for
$2.4 billion. Separately, E.ON acquired BP's wholly-owned subsidiary Gelsenberg,
which held a 25.5% stake in Germany's largest natural gas distributor, Ruhrgas
for $2.3 billion.
As a condition of regulatory approval of the deal BP was required to
dispose of 4% of the combined 26.5% retail market share of BP and Aral in
Germany, 45% of its stake in the Bayernoil refinery, two of its three
shareholdings in the ARG ethylene pipeline, and to make it possible for a new
entrant to supply aviation fuel on competitive terms at Frankfurt airport.
During 2003, BP expects to fully comply with the conditions imposed.
Separately, BP and E.ON reached agreement to sell Veba's oil and natural
gas exploration and production business to Petro-Canada for $2.1 billion, of
which $1.6 billion was received in 2002 and the remainder is subject to
preemption rights.
Recent Developments
BP and the Alfa Group and Access-Renova (AAR) announced on February 11,
2003, that they have agreed in principle to combine most of their interests in
Russia to create the country's third biggest oil business, in which they will
each have a 50% stake.
BP intends to contribute its holding in Sidanco, its stake in Rusia
Petroleum, its interest in the Sakhalin V exploration licence and its holding in
the BP Moscow retail network.
AAR intends to contribute its holdings in TNK and Sidanco, its share of
Rusia Petroleum, its stake in the Rospan gasfield in West Siberia and its
interest in the Sakhalin IV and V exploration licence. Neither AAR's association
with Slavneft, nor BP's interest in LukArco or the Russian elements of BP's
international businesses such as lubricants, marine and aviation, are included
in the transaction.
The transaction, which will be effective from January 1, 2003, is scheduled
for completion in the summer of 2003.
Page 14
For its 50% stake in the new company BP will pay AAR $3 billion in cash on
completion of the deal, adjusted to take account of the period between the
effective date and the completion date. BP will subsequently pay three annual
tranches of $1.25 billion in BP shares, valued at market prices prior to each
annual payment.
The new company will be called TNK-BP. We believe it should generate
sufficient cash to finance its investment programme and it is not expected to
need additional funding from its shareholders.
Financial and Operating Information
The following table summarizes the Group's turnover, results and capital
expenditure for the last five years and total assets at the end of each of those
years.
Years ended December 31,
----------------------------------------------------
2002 2001 2000 1999 1998
----- ----- ----- ----- -----
($ million)
Turnover........................................ 180,186 175,389 161,826 101,180 83,732
Less: joint ventures............................ 1,465 1,171 13,764 17,614 15,428
----- ----- ----- ----- -----
Group turnover (sales to third parties)......... 178,721 174,218 148,062 83,566 68,304
Total replacement cost operating profit......... 10,246 16,027 17,679 8,894 6,521
Profit for the year*............................ 6,845 6,556 10,120 4,566 2,651
Capital expenditure and acquisitions............ 19,111(a) 14,124 47,613(a) 7,345(b) 10,362
Total assets.................................... 159,125 141,970 144,862 89,481 84,835
--------
* After minority shareholders' interest
(a) Capital expenditure and acquisitions for 2002 includes $5,038 million for
the acquisition of Veba, and for 2000 includes $27,506 million for the
acquisition of ARCO and $8,936 million for other significant one-off cash
investments.
(b) Capital expenditure and acquisitions in 1999 reflected reduced investment
following the merger of BP and Amoco.
With the exception of the ARCO acquisition, all capital expenditure and
acquisitions have been financed from cash flow from operations, disposal
proceeds and external financing.
Information for 2002, 2001 and 2000 concerning the profits and assets
attributable to the businesses and to the geographical areas in which the Group
operates is set forth in Item 18 -- Financial Statements -- Note 49.
Page 15
The following table shows our production for the last five years and the
estimated proved oil and natural gas reserves at the end of each of those years.
Years ended December 31,
--------------------------------------------------
2002 2001 2000 1999 1998
----- ----- ----- ----- -----
Total crude oil production (thousand barrels
per day) (a)........................................ 2,018 1,931 1,928 2,061 2,049
Total natural gas production (million cubic
feet per day) (a)................................... 8,707 8,632 7,609 6,067 5,808
Total estimated net proved crude oil reserves
(million barrels) (b)............................... 7,762 7,217 6,508 6,535 7,304
Total estimated net proved natural gas
reserves (billion cubic feet) (b)................... 45,844 42,959 41,100 33,802 31,001
----------
(a) Includes BP's share of equity-accounted entities.
(b) Net proved reserves of crude oil and natural gas exclude production
royalties due to others and reserves of equity-accounted entities.
During 2002, 2,016 million barrels of oil and natural gas, on an oil
equivalent* basis (mmboe), were added to BP's proved reserves (excluding
purchases, sales and equity accounted entities), more than replacing the volume
produced. After allowing for production, which amounted to 1,154 mmboe, BP's
proved reserves increased to 15,666 mmboe. These proved reserves are mainly
located in the USA (39%), Trinidad and Tobago (19%) and the UK (11%).
----------
* Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1
million barrels.
Page 16
SEGMENTAL INFORMATION
The following tables show turnover and replacement cost profit by business
and by geographical area, for the years ended December 31, 2002, 2001 and 2000.
Years ended December 31,
-------------------------------------------------------------------------------------
2002 2001(c) 2000(c)
--------------------------- ------------------------ -----------------------
Sales Sales to Sales Sales to Sales Sales to
Total between third Total between third Total between third
Turnover (a) sales businesses parties sales businesses parties sales businesses parties
----- ---------- ------- ----- ---------- ------- ----- ---------- --------
($ million) ($ million) ($ million)
By business
Exploration and
Production......... 25,753 18,556 7,197 28,229 19,660 8,569 30,942 16,787 14,155
Gas, Power and
Renewables.......... 37,357 1,320 36,037 39,442 2,954 36,488 21,203 346 20,857
Refining and
Marketing........... 125,836 3,366 122,470 120,233 2,903 117,330 107,883 5,923 101,960
Chemicals............. 13,064 557 12,507 11,515 233 11,282 11,247 216 11,031
Other businesses
and corporate...... 510 -- 510 549 -- 549 59 -- 59
------- ------ ------- ------- ------ ------- ------ ------ ------
Group turnover........ 202,520 23,799 178,721 199,968 25,750 174,218 171,334 23,272 148,062
======= ====== ======= ====== ======= ======
Share of joint
venture sales...... 1,465 1,171 13,764
------- ------- -------
180,186 175,389 161,826
======= ======= =======
Sales Sales to Sales Sales to Sales Sales to
Total between third Total between third Total between third
sales businesses parties sales businesses parties sales businesses parties
----- ---------- ------- ----- ---------- ------- ----- ---------- --------
($ million) ($ million) ($ million)
By geographical area
UK (b)................ 48,748 14,673 34,075 47,618 13,467 34,151 45,400 10,970 34,430
Rest of Europe........ 46,518 7,980 38,538 36,701 7,603 29,098 20,553 1,911 18,642
USA................... 80,381 2,099 78,282 84,696 939 83,757 71,084 829 70,255
Rest of World......... 34,401 6,575 27,826 33,911 6,699 27,212 31,014 6,279 24,735
------- ------- ------- ------- ------- ------- ------- ------ -------
210,048 31,327 178,721 202,926 28,708 174,218 168,051 19,989 148,062
======= ======= ======= ======= ======= ======= ======= ====== =======
Share of joint venture
sales
UK 129 13 3,314
Rest of Europe 298 30 12,316
USA 236 318 270
Rest of World 802 810 686
------- ------- -------
1,465 1,171 16,586
Sales between areas -- -- 2,822
------- ------- -------
1,465 1,171 13,764
======= ======= =======
------------
(a) Turnover to third parties is stated by origin which is not materially
different from turnover by destination. Transfers between Group companies
are made at market prices taking into account the volumes involved.
(b) UK area includes the UK-based international activities of Refining and
Marketing.
(c) 2000 and 2001 have been restated to reflect the transfer of the solar,
renewables and alternative fuels activities from Other Businesses and
Corporate to Gas, Power and Renewables.
Page 17
Group Total Replacement
replacement replacement cost profit
cost cost before
operating Joint Associated operating Exceptional interest
Analysis of replacement cost profit profit(a) ventures undertakings profit(a) items(b) and tax
---------- -------- ------------ ----------- ----------- -----------
($ million)
Year ended December 31, 2002
By business
Exploration and Production.................. 8,595 343 268 9,206 (726) 8,480
Gas, Power & Renewables..................... 247 -- 107 354 1,551 1,905
Refining and Marketing...................... 668 24 180 872 613 1,485
Chemicals................................... 527 (21) 9 515 (256) 259
Other businesses and corporate.............. (753) -- 52 (701) (14) (715)
------ ------ ------ ------ ------ ------
9,284 346 616 10,246 1,168 11,414
====== ====== ====== ====== ====== ======
By geographical area
UK (c)...................................... 1,701 (15) 10 1,696 (88) 1,608
Rest of Europe.............................. 1,572 (1) 132 1,703 1,817 3,520
USA......................................... 2,665 16 209 2,890 (242) 2,648
Rest of World............................... 3,346 346 265 3,957 (319) 3,638
------ ------ ------ ------ ------ ------
9,284 346 616 10,246 1,168 11,414
====== ====== ====== ====== ====== ======
Year ended December 31, 2001(d)
By business
Exploration and Production.................. 11,802 373 186 12,361 195 12,556
Gas, Power & Renewables..................... 304 -- 184 488 -- 488
Refining and Marketing...................... 3,295 83 195 3,573 471 4,044
Chemicals................................... 21 (13) 120 128 (297) (169)
Other businesses and corporate.............. (598) -- 75 (523) 166 (357)
------ ------ ------ ------ ------ ------
14,824 443 760 16,027 535 16,562
====== ====== ====== ====== ====== ======
By geographical area
UK (c)...................................... 2,657 (3) 14 2,668 (319) 2,349
Rest of Europe.............................. 1,579 (1) 236 1,814 33 1,847
USA......................................... 6,632 76 233 6,941 289 7,230
Rest of World............................... 3,956 371 277 4,604 532 5,136
------ ------ ------ ------ ------ ------
14,824 443 760 16,027 535 16,562
====== ====== ====== ====== ====== ======
Year ended December 31, 2000 (d)
By business
Exploration and Production.................. 13,359 384 229 13,972 119 14,091
Gas, Power & Renewables..................... 370 -- 162 532 2 534
Refining and Marketing...................... 2,887 433 166 3,486 98 3,584
Chemicals................................... 576 (9) 193 760 (212) 548
Other businesses and corporate.............. (1,113) -- 42 (1,071) 213 (858)
------ ------ ------ ------ ------ ------
16,079 808 792 17,679 220 17,899
====== ====== ====== ====== ====== ======
By geographical area
UK (c)...................................... 3,629 106 38 3,773 12 3,785
Rest of Europe.............................. 1,488 264 261 2,013 (19) 1,994
USA......................................... 6,929 44 246 7,219 459 7,678
Rest of World............................... 4,033 394 247 4,674 (232) 4,442
------ ------ ------ ------ ------ ------
16,079 808 792 17,679 220 17,899
====== ====== ====== ====== ====== ======
------------
(a) Replacement cost operating profit is before inventory holding gains and
losses and interest expense, which is attributable to the corporate
function. Transfers between Group companies are made at market prices
taking into account the volumes involved.
(b) Exceptional items comprise profit or loss on the sale of fixed assets and
businesses and termination of operations.
(c) UK area includes the UK-based international activities of Refining and
Marketing.
(d) 2000 and 2001 have been restated to reflect the adoption of FRS 19 and the
transfer of the solar, renewables and alternative fuels activities from
Other Businesses and Corporate to Gas, Power and Renewables.
Page 18
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 pipelines,
processing and export terminals and LNG processing facilities -- the midstream
activities. We have Exploration and Production interests in 28 countries. Areas
of activity include the USA, UK, Norway, Canada, South America, Africa, the
Middle East, and Asia. Production during 2002 came from 23 countries. Our most
significant midstream activities are in three major pipelines -- the Trans
Alaska Pipeline System (BP 46.9%); the Forties Pipeline System (BP 100%) and the
Central Area Transmission System pipeline (BP 29.5%) both in the UK sector of
the North Sea; three major LNG plants -- the Atlantic LNG plant in Trinidad (BP
34% in Train 1 and 42% in Trains 2 and 3), in Indonesia through the joint
venture operating company Virginia Indonesia Co. (VICO) (BP 50%) and in
Australia through our share of LNG from the North West Shelf natural gas
development (BP 16.7%).
Years ended December 31,
---------------------------------
2002 2001 2000
------- ------ ------
($ million)
Turnover (a).................................................... 25,753 28,229 30,942
Total replacement cost operating profit......................... 9,206 12,361 13,972
Total assets.................................................... 72,801 70,017 66,405
Capital expenditure and acquisitions............................ 9,699 8,861 6,383
($ per barrel)
Average BP crude oil realizations............................... 22.69 22.50 26.63
Average West Texas Intermediate oil price....................... 26.14 25.89 30.38
Average Brent oil price......................................... 25.03 24.44 28.44
($ per thousand cubic feet)
Average BP natural gas realizations............................. 2.46 3.30 2.91
Average BP US natural gas realizations.......................... 2.63 3.99 3.72
($ per mmbtu)
Average Henry Hub gas price (b)................................. 3.22 4.26 3.90
----------
(a) Excludes BP's share of joint venture turnover of $539 million in 2002, $666
million in 2001, and $585 million in 2000.
(b) Henry Hub First of Month Index.
Strategy and Overview
Our strategy is to deliver a competitive combination of production growth
and returns over the long-term. Simply stated, our strategy is to create, build
and produce material businesses in some of the world's most promising
hydrocarbon provinces. It is underpinned by a focus on creating value through
four stages in the basin lifecycle: creating new profit centers by accessing the
right basins; building projects of the highest quality and value through choice
amongst a portfolio of opportunities; maximizing the productivity of the
existing profit centers by managing the relevant assets for cash and returns;
and by understanding when our best option is to stop investing in opportunities
that others may find more valuable. In all phases of the lifecycle, the strategy
has two basic principles: focus to build material businesses, that is pursuing
only those opportunities that are of sufficient size to enable higher returns
through cost efficiency, and choice of investments to drive quality.
Page 19
The first element underpinning our Exploration and Production strategy is
to access the right basin opportunities. We aim to do this through focused
exploration projects in both proved and emerging basins and selective satellite
projects adjacent to existing hubs, taking advantage of existing infrastructure.
Our exploration programme today is focused primarily on the Deepwater Gulf of
Mexico, Trinidad and Angola.
The second element underpinning our strategy is to build new profit centers
through the choice of the best projects. We are currently building five new
profit centers in Deepwater Gulf of Mexico, Trinidad, Angola, Azerbaijan, and
Asia Pacific LNG. In these areas, several key projects provide the foundation
for volume growth and improved margins over the next several years. In 2002, we
approved $5.2 billion of new projects in these five areas. Combined with other
projects in these areas, we currently have $15.9 billion of major projects under
construction and another estimated $8.5 billion of additional opportunities in
various appraisal stages.
The third element underpinning our strategy is to maximize the value of our
existing profit center portfolio. We accomplish this through focused pursuit of
production optimization and cost efficiencies. Production optimization is
delivered through reservoir management, improved facility runtime and enhanced
recovery technologies to mitigate volume decline and increasing ultimate
recoveries in mature fields. Continuous improvement in cost efficiency is also a
critical element. We drive cost efficiencies through leveraging economies of
scale in key producing basins; and through the application of technology,
focused on improving system efficiency and operational reliability.
The fourth element underpinning our strategy is to understand when to stop
investing. We have a rigorous process for evaluating the economic merit and
strategic fit of all investment opportunities. With our sizeable portfolio of
opportunities in the profit centers we are building, we are afforded the benefit
of choosing the best projects for funding. In the existing profit centers, we
globally rank the attractiveness of investment opportunities and choose the best
for funding. Both in the new profit centers and in the existing profit centers,
we are disposing of investments that do not fit our criteria, but in which
others may see value.
Recent Developments
As part of our aim to focus on retention of a greater share of large,
low-cost oil and gas fields, the sale of our interests in the Arbroath,
Arkwright and Montrose fields to Paladin Resources plc for $80.5 million was
announced in December 2002. It is anticipated that this will complete in the
second quarter of 2003.
As part of implementing our strategy, a number of other portfolio changes
have been announced or completed post December 31, 2002.
In addition to the recent transaction in Russia which is described in this
item under General - Business Overview and Strategy, these activities include:
-- In October 2002, Repsol-YPF notified us of their intent to exercise
their option to acquire a further 20% of our upstream interests in
Trinidad and on January 2, 2003, we completed this transaction. Repsol
now has a 30% interest in BP Trinidad and Tobago LLC. This transaction
gives leverage for our upstream position in Trinidad to access gas
markets and growth opportunities in Spain, thus providing a further
platform for BP's future gas growth in Trinidad.
-- In January 2003, we announced the divestment of our 96.14% interest in
the North Sea Forties oilfield along with some 61 mature, primarily
gas-producing assets in the shallow water of the Gulf of Mexico to
Apache for $1.3 billion.
Page 20
-- On February 26, 2003, we completed an exchange of interests with
Amerada Hess under which we will swap our 25% interest in block A-18
of the Malaysia Thailand Joint Development Area (JDA), for Amerada
Hess's interests in Colombia and $10 million in cash. The Colombian
interests include a 12% stake in the Santiago de las Atalayas,
Tauramena and Rio Chitamena contracts; 10% in the Recetor Association
contract; and a 9.6% stake in the OCENSA pipeline. This transaction
adds some 58 million barrels of proven reserves to BP's Colombian
portfolio.
-- As part of building our competitive position in LNG in the Asia
Pacific region we announced, in February 2003, the sale of 12.5 per
cent of our Tangguh LNG project to China National Offshore Oil
Corporation (CNOOC) for $275 million. This completed the Heads of
Agreement, which was signed in September 2002 concurrent with the
signing of the LNG supply agreement to Fujian. The involvement of
CNOOC in this project should afford greater access to the growing
Chinese LNG market.
-- Other restructuring activities have included the agreement to sell a
package of assets primarily in North America. The sale is scheduled to
be completed in April 2003.
-- In February 2003, we announced the sale to Perenco of certain Southern
North Sea gas interests for $162 million, and Venezuelan interests for
$160 million.
-- In February 2003, we redeemed our 3% five year Exchangeable Bond for
Lukoil ADRs. This transaction completed the monetization of our stake
in the Russian Oil company Lukoil with proceeds of $420 million being
received. The stake in Lukoil was obtained through the acquisition of
ARCO.
Upstream Activities
Exploration
The Group explores for oil and natural gas under a wide range of licensing,
joint venture and other contractual agreements. We may do this alone or, more
frequently, with partners. BP acts as operator for many of these ventures.
Our exploration and appraisal costs in 2002 were $1,108 million compared to
$1,102 million in 2001. About 55% of 2002 exploration and appraisal capital was
directed towards appraisal activity as we delineated the discoveries made during
1999, 2000, and 2001. In 2002, we participated in 110 gross (52 net) exploration
and appraisal wells in 18 countries. The principal areas of activity were
Angola, Egypt, Norway, Trinidad, and the USA.
In 2002, we obtained upstream rights in several new tracts, which include
the following:
-- In Norway's 17th License Round, BP gained a 20% interest in the 'Grip
High' block, which lies immediately due north of the Ormen Lange
field.
-- In Russia, a five-year exploration license for part of the offshore
Sakhalin V block was awarded to Rosneft and through an alliance
agreement, the joint venture with Rosneft and
Rosneft-Sakhalinmorneftegas in which BP holds a 49% interest will
carry out the exploration on behalf of the licence holder.
-- In the Gulf of Mexico, BP was successful in the OCS Lease Sales 182
and 184 with bids on 58 blocks, of which 40 were won, for an overall
success rate of 69%.
-- In deepwater Brazil, we extended our offshore Foz do Amazonas licence
in Block BM-FZA-1 (BP 30% and operator) for 3 years following
encouraging exploration activity during 2002.
Page 21
In 2002, we were involved in discoveries in Angola, Egypt, Trinidad, 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. Our 2002 discoveries included the following:
-- In Angola, BP made the country's first discovery in the 'ultra deep
water' (greater than 1,500 metres) acreage with the Plutao well in
Block 31 (BP 26.7% and operator). Continued success was experienced in
the established partner operated deepwater blocks; in Block 15 (BP
26.7%) the Reco-Reco, Mondo North, and Marimba South discoveries, and,
in Block 17 (BP 16.7%), the Zinia discovery.
-- In Egypt, BP was involved in seven gas discoveries in the Nile Delta.
Four of these; El Max, El Bahig, Abu Sir and El King, were made in the
West Med Concession under an arrangement in which we reduced our
interest from 16.7% to 10%. In the West Med Deep Concession, BP made
the Ruby discovery (BP 80%). Viper-1 (BP 30%) in North Idku, and
Tenin-1 (BP 50%) in East Deep Delta Marine were also successful. Oil
exploration close to established production in the Gulf of Suez
resulted in the Luli discovery (BP 100%).
-- In Trinidad new gas reservoirs were discovered in the Red Mango No.2
and Iron Horse wells off the east coast of the island. These interests
are held in a fully consolidated subsidiary in which in 2002 there was
a 10% minority interest. In the fourth quarter we determined the
Catfish well was a dry hole and consequently the cost was written off.
-- In the Deepwater Gulf of Mexico, discoveries include the
partner-operated Great White (BP 33.3%) in the Alaminos Canyon area,
and the partner operated Shenzi well (BP 28%) in the Green Canyon
area, seven miles north west of BP's Atlantis development (BP 56%).
Infrastructure-led efforts in the Mississippi Canyon area were
successful with the King West discovery (BP 100%), adjacent to the
King Development (BP 100%), the Dorado discovery, adjacent to the
Marlin TLP (BP 75%) and the Deimos discovery (BP 28.5%) in the Mars
basin. The deepwater prospect Neptune was relinquished after we
concluded that the discovered volumes did not rank highly enough in
our portfolio of investment opportunities.
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, 2002, 2001, and 2000 and reserves
changes for each of the three years then ended are set out in the Supplementary
Oil and Gas Information section in Item 18 -- Financial Statements.
Total hydrocarbon proved reserves, on an oil equivalent basis and excluding
equity-accounted entities, comprised 15,666 mmboe at December 31, 2002, an
increase of 7.1% compared with December 31, 2001. Natural gas represents about
50% of these reserves. Reserve replacement through extensions, discoveries,
revisions and improved recovery, for the Group excluding equity accounted
entities, exceeded production for the tenth consecutive year with a ratio of
175%.
In 2002, total additions to the Group's proved reserves (excluding
purchases and sales and equity-accounted entities) amounted to 2,016 mmboe,
mostly through extensions to existing fields and discoveries of new fields. The
principal reserve additions were in Algeria (In Amenas Train 3), Angola (Kizomba
B), Azerbaijan (Azeri-Chirag-Gunashli Phase 2), Gulf of Mexico (Mad Dog) and
Trinidad (reserves to support the 4th train of the Atlantic LNG project).
Page 22
Our total hydrocarbon production (including equity-accounted entities)
during 2002 averaged 3,519 thousand barrels of oil equivalent per day (mboe/d),
an increase of 100 mboe/d, or 2.9% compared with 2001, as production declines in
mature fields were more than offset by production start-ups, build-ups to full
production and acquisitions. 39% of our production was in the USA, 21% in the UK
and 9% from equity-accounted entities, of which 23% is from Sidanco.
Page 23
The following tables show BP's production by major field for 2002, 2001 and
2000, and BP's aggregate estimated net proved reserves as at December 31, 2002:
Crude oil (a)
Net production
-------------------------------
Production Field or Area Interest 2002 2001 2000
------------- -------- ----- ----- -----
(%) (thousand barrels per day)
Alaska (b) Prudhoe Bay* 26.3 113 123 146
Kuparuk 39.2 74 76 81
Milne Point* 100.0 44 45 40
Northstar* 98.8 36 3 --
Endicott* 67.9 15 19 21
Point McIntyre 26.4 9 10 16
Other Various 18 12 10
------ ------ ------
Total Alaska 309 288 314
------ ------ ------
Lower 48 States onshore Total Various 192 213 218
------ ------ ------
Gulf of Mexico (b) Mars 28.5 41 42 38
Troika 33.3 20 25 28
Pompano* 75.0 23 21 26
Ursa 22.7 20 23 19
Crosby 50.0 19 -- --
Marlin* 86.3 19 19 1
Other Various 122 113 85
------ ------ ------
Total Gulf of Mexico 264 243 197
------ ------ ------
Total USA 765 744 729
------ ------ ------
UK offshore (b) Foinaven* 72.0 72 60 64
ETAP+ Various 61 80 85
Forties*(c) 96.1 50 51 53
Schiehallion/Loyal* Various 43 40 44
Harding* 70.0 42 42 57
Magnus* 85.0 31 37 47
Andrew* 62.8 23 25 33
Miller* 52.0 11 15 22
Other Various 96 99 89
------ ------ ------
Total UK offshore 429 449 494
Onshore Wytch Farm* 67.8 32 36 40
------ ------ ------
Total UK 461 485 534
------ ------ ------
Norway Draugen 18.4 37 40 38
Valhall* 28.1 21 22 23
Ula* 80.0 18 18 16
Gyda* 61.0 8 12 12
Other including Netherlands Various Various 20 8 1
------ ------ ------
Total Rest of Europe Various 104 100 90
------ ------ ------
---------------
* BP operated.
+ BP operates the majority of the fields in this area.
Page 24
Net production
----------------------------
Production Field or Area Interest 2002 2001 2000
------------- -------- ----- ----- -----
(%) (thousand barrels per day)
Angola Girassol 16.7 29 1 --
Australia Various 16.7 43 40 37
Azerbaijan Azeri-Chirag-Gunashli* 34.1 38 35 30
Canada (b) Various Various 16 18 19
Colombia Various Various 46 48 52
Egypt October 50.0 16 22 30
Other Various 69 69 78
Trinidad Various 100.0 67 48 47
Venezuela Various Various 51 54 46
Other (b) Various Various 61 59 51
------ ------ ------
Total Rest of World 436 394 390
------ ------ ------
Total Group 1,766 1,723 1,743
====== ====== ======
Equity-accounted entities
Abu Dhabi (d) Various Various 113 126 127
Russia Various Various 73 20 11
Argentina Various Various 53 50 40
Other Various Various 13 12 7
------ ------ ------
Total equity-accounted entities 252 208 185
------ ------ ------
Total Group and BP share
of equity-accounted entities (e) 2,018 1,931 1,928
====== ====== ======
---------------
* BP operated.
December 31, 2002
-----------------------------------------------------------------
Rest of Rest of
Estimated net proved reserves (a) UK Europe USA World Total
------ ------ ------ ------ ------
(millions of barrels)
Subsidiary undertakings
Developed............................... 858 250 2,225 1,002 4,335
Undeveloped............................. 269 99 1,336 1,723 3,427
------ ------ ------ ------ ------
1,127 349 3,561 2,725 7,762
====== ====== ====== ====== ======
Equity-accounted entities 1,403
------
Total Group and BP share
of equity-accounted entities 9,165
======
------
Page 25
Natural gas (a)(f)
Net production
-------------------------------
Production Field or Area Interest 2002 2001 2000
------------- -------- ----- ----- -----
(%) (million cubic feet per day)
Lower 48 States onshore (b) San Juan Coal* Various 601 615 563
Arkoma Various 206 219 94
San Juan Conventional + Various 196 217 185
Hugoton + Various 169 180 170
Tuscaloosa + Various 138 187 171
Jonah* 75.2 113 109 77
Wamsutter* 70.5 108 100 100
Whitney Canyon + Various 50 50 47
Anschutz Ranch East* Various 28 45 55
Moxa Arch* 41.0 54 43 52
Other Various 583 595 647
------ ------ ------
Total Lower 48 States onshore 2,246 2,360 2,161
------ ------ ------
Alaska Various Various 52 11 9
------ ------ ------
Gulf of Mexico (b) Marlin* 100.0 106 79 3
Pompano* 73.7 63 35 45
Mica 50.0 58 27 --
Ram Powell (VK 912) 31.0 54 58 60
Matagorda Island 623* 43.5 48 76 78
Matagorda Island 519* 82.3 47 40 56
Mars 28.5 38 41 33
Other Various 771 827 609
------ ------ ------
Total Gulf of Mexico 1,185 1,183 884
------ ------ ------
Total USA 3,483 3,554 3,054
------ ------ ------
UK offshore (b) Bruce* 37.0 221 256 201
Marnock* 62.0 135 125 148
Braes Various 116 100 99
West Sole* 100.0 72 81 89
Armada 18.2 71 71 75
Ravenspurn South* 100.0 56 66 77
Britannia 9.0 56 65 41
Amethyst* 59.5 52 68 56
East Leman* 48.4 44 59 58
Viking Complex 50.0 42 54 81
Vulcan 50.0 34 33 44
Other Various 646 730 678
Onshore Wytch Farm 67.8 5 5 5
------ ------ ------
Total UK 1,550 1,713 1,652
------ ------ ------
Netherlands P/18-2* 48.7 41 47 52
Other Various 46 52 43
Norway Various Various 60 48 41
------ ------ ------
Total Rest of Europe 147 147 136
------ ------ ------
---------------
* BP operated.
+ BP operates the majority of the fields in this area.
Page 26
Net production
-------------------------------
Production Field or Area Interest 2002 2001 2000
------------- -------- ----- ----- -----
(%) (million cubic feet per day)
Rest of World
Australia Various 16.7 295 237 205
Canada (b) Kirby* 95.0 66 72 69
Ricinus* 47.2 54 61 52
Brazeau River Gas* 66.9 53 71 63
Marten Hills* 93.5 32 45 47
Other Various 309 335 351
China Yacheng* 34.0 102 108 77
Egypt Temsah 50.0 84 26 --
Ha'py 50.0 74 66 63
Other Various 98 98 86
Indonesia Pagerungan* 100.0 189 242 199
Sanga-Sanga (direct) 26.3 174 164 120
Other* 46.0 94 95 54
Sharjah Sajaa* 40.0 110 125 145
Other Various 24 35 39
Trinidad Mahogany* 100.0 521 529 530
Amherstia* 100.0 492 244 17
Immortelle* 100.0 154 128 232
Flamboyant* 100.0 40 52 69
Other* 100.0 31 58 37
Other (b) Various Various 148 82 49
------ ------ ------
Total Rest of World 3,144 2,873 2,504
------ ------ ------
Total Group 8,324 8,287 7,346
====== ====== ======
Equity-accounted entities
Argentina Various Various 251 236 187
Other Various Various 132 109 76
------ ------ ------
Total equity-accounted entities 383 345 263
------ ------ ------
Total Group and BP share
of equity-accounted entities 8,707 8,632 7,609
====== ====== ======
December 31, 2002
-----------------------------------------------------------------
Rest of Rest of
Estimated net proved reserves (a) UK Europe USA World Total
------ ------- ------ ------- ------
(millions of barrels)
Subsidiary undertakings
Developed............................... 3,215 216 12,102 8,240 23,773
Undeveloped............................. 651 44 2,259 19,117 22,071
------ ------ ------ ------ ------
3,866 260 14,361 27,357 45,844
====== ====== ====== ====== ======
Equity-accounted entities 2,945
------
Total Group and BP share
of equity-accounted entities 48,789
======
Page 27
----------
(a) Net proved reserves of crude oil and natural gas, stated as of December 31,
2002, exclude production royalties due to others, and include minority
interests in consolidated operations.
(b) In 2002, BP acquired additional working interest in the Badin acreage
(Pakistan) from the government and disposed of its interest in the Al
Rayyan field (Qatar), Qadirpur field (Pakistan) and Elgin/Franklin field
(UK). In 2001, BP purchased part of the interests of Statoil in Vietnam and
the interest of Inaquimicas in Cusiana/Cupiagua in Colombia. In 2000, BP
acquired the interests of ARCO outside Alaska. At the same time, a deal was
concluded (primarily with Exxon and Phillips) in which the oil and natural
gas interests in Prudhoe Bay (and some of the associated fields) were
realigned. We also disposed of our interest in Altura Energy. In addition
to portfolio management in the USA and Canada, we disposed of certain of
our interests in Venezuela, Colombia and the UK and acquired an interest in
Pakistan as part of the Burmah Castrol acquisition.
(c) The sale of BP's interest in the Forties field was announced in January
2003.
(d) The BP Group holds proportionate interests, through associated
undertakings, in onshore and offshore concessions in Abu Dhabi expiring in
2014 and 2018, respectively.
(e) Includes NGLs from processing plants in which an interest is held of 69, 78
and 41 thousand barrels per day for 2002, 2001, and 2000 respectively.
(f) Natural gas production volumes exclude gas consumed in operations within
the lease boundaries of the producing field.
Page 28
United States
We are the largest producer of both crude oil and natural gas in the USA.
2002 crude oil production at 765 thousand barrels per day (mb/d) increased 3%
from 2001, while natural gas production at 3,483 million cubic feet per day
(mmcf/d) decreased 2% over 2001.
During 2002, BP operations experienced significant reductions in production
due to adverse weather and natural events. Hurricanes and tropical storms in the
Gulf of Mexico during September and October resulted in multiple shut-ins of
Gulf of Mexico production and some Gulf Coast production, which reduced full
year production by 24 mboe/d. In October 2002, an earthquake forced the shut-in
of the Trans Alaska Pipeline for 3 days while inspection and immediate repairs
were made. No oil was spilled, however, a 3-mboe/d reduction in 2002 production
resulted from the shutdown.
Development expenditure in the USA (excluding pipelines) during 2002 was
$3,618 million, compared with $3,723 million in 2001, a decrease of 3%.
Our activities within the United States take place in four main areas.
Significant events during 2002 within each of these are indicated below.
Deepwater Gulf of Mexico
Deepwater Gulf of Mexico is one of our five new profit centres and our
largest area of growth in the USA. In 2002, our Deepwater Gulf of Mexico crude
oil production was 205 mb/d, up 15% from 2001 levels. Gas production was 511
mmcf/d, up over 26% from 2001 levels.
Growth in 2002 was driven by new field start-up activity, as well as strong
performance from the existing major facility hubs. Key events include:
-- The King MC85 subsea tieback (BP 100%) started production via
facilities on the Marlin platform in April 2002.
-- The King's Peak development, 3 subsea wells, (BP 100%) started
production in September 2002.
-- Production started from the Horn Mountain field (BP 67% and operator)
in November 2002.
-- The Princess development (BP 23%), drilled from the Ursa platform,
started producing in November 2002.
-- Aspen (BP 40% and operator), a subsea development to the non-operated
Bullwinkle platform, commenced production in December 2002.
Development of five major projects continued in the Gulf of Mexico during
2002 -- Na Kika (BP 50% and operator post construction), Holstein (BP 50% and
operator), Mad Dog (BP 60.5% and operator), Thunder Horse (BP 75% and operator)
and Atlantis (BP 56% and operator).
Gulf of Mexico Shelf
The Shelf is a mature basin, with high decline rates that average 30-40%
per year. In 2002, BP's gas production from Gulf of Mexico Shelf operations was
674 mmcf/d, which was down 13% compared to 2001. BP produced 7% of total Gulf of
Mexico Shelf gas production, which, in turn, supplies 15% of the US gas demand.
Crude oil and NGL production was 59 mb/d, down 8% compared to 2001. We operate
more than 200 platforms and 700 wells on the Shelf, in water up to 1,500 feet
deep. We operated 8 rigs and drilled 32 operated wells in 2002. The sale to
Apache announced in January 2003 included 61 small, mainly gas producing fields
on the Shelf, which accounted for approximately 40% of 2002 production.
Page 29
Lower 48 States
In the Lower 48 States, we remain the largest producer of natural gas,
accounting for approximately 6% of total US onshore natural gas production.
Production comes from more than 11,000 operated wells, in over 900 oil and gas
fields, situated principally in the states of Colorado, Kansas, Louisiana, New
Mexico, Oklahoma, Texas and Wyoming.
In 2002, crude oil production was 192 mb/d, down 10% from 2001 levels.
Natural gas production was 2,246 mmcf/d in 2002, down 5% from 2001 production.
This is a mature region and reduced production is driven by natural decline. In
2002, we operated 76 drilling and service rigs and drilled 400 wells, finding
and developing additional reserves to replace 78% of production. More than 3,000
well workovers and maintenance interventions were performed.
Our production in the onshore Lower 48 States was derived primarily from
the following areas:
-- In the mid-continent states (Texas, Oklahoma, Kansas and Louisiana)
our operations produced 915 mmcf/d of natural gas and 54 mb/d of oil
and NGL's in 2002. Improved efficiency to maintain the production rate
in mature areas is the key to continued success in these assets.
Examples of improved efficiency include:
-- Texas Panhandle (Anadarko Basin) - BP's application of horizontal
drilling in the Courson Ranch field in 2002 has raised production
from 2 mmcf/d to 8 mmcf/d by year end with the possibility of
further development in 2003. The switch from conventional
vertical wells to horizontal completions has resulted in a 33%
improvement in reserves/spend efficiency.
-- Eastern Oklahoma (Red Oak field) - Red Oak field's 2002
production exceeded 1997 levels in what was previously thought to
be a fully developed reservoir. This was accomplished through an
ongoing successful infill-drilling programme based on the use of
3D seismic.
-- Southwest Kansas (Hugoton and Panoma fields) - We continued to
manage the decline of the Hugoton field, down 4% for 2002. We
achieved this through an active wellwork and facilities
maintenance programme, installation of additional compression and
development drilling. Optimization of the entire work programme
was facilitated by implementation of an innovative multiwell
visualisation tool, which was developed by the Hugoton team. The
80-year-old Hugoton field is the largest natural gas field in the
Lower 48 States and has previously experienced annual decline
rates as high as 20%.
-- Louisiana (Tuscaloosa Trend) - BP is now delivering initial
production rates of 50 to 60 mmcf/d per well from the Tuscaloosa
asset, significantly higher than the historical rates of 20
mmcf/d. BP's development strategy in the trend is to look for
deeper gas producing horizons in areas that are also likely to
have shallower secondary gas producing horizons. BP has optimized
well design and improved the time from completion to first gas
sale by 60% compared with 2001. This achievement resulted in an
average of 20 additional days per well of production delivery to
the market.
-- The Southern Wyoming (Overthrust Belt, Greater Green River Basin)
operations produced 371 mmcf/d of natural gas and 39 mb/d of crude oil
in 2002 with both the Wamsutter and Jonah fields achieving record
production. Drilling activity in 2002 continued as part of a
multi-year drilling programme comprising both extension and infill
wells in the Jonah and Wamsutter fields. In 2002, BP drilled 123 wells
with 6 rigs in Wamsutter. The previous drilling time benchmark for BP
in the basin was beaten by 40% of the wells drilled in 2002, reducing
the asset's overall drilling time by 20%.
Page 30
-- Colorado and New Mexico (San Juan Basin Coal and Conventional Gas
fields) operations produced 807 mmcf/d of natural gas in 2002,
maintaining BP's position as the largest coalbed methane producer in
the largest coalbed methane region in the USA. In 2002, the unit
reduced overall well costs by 10% to 15% by reducing site
construction, drilling and completion costs, while at the same time
increasing initial production rates from new wells and reducing cycle
time from well spud to gas sales.
Alaska
In Alaska, crude oil production in 2002 was 309 mb/d, an increase of 7%
from 2001, due principally to the start-up of Northstar and the performance of
satellite fields around Prudhoe Bay.
Key activities during 2002 in Alaska included:
-- As part of maximising the productivity of our existing profit centers,
active reservoir management at Alaska's largest producing field,
Prudhoe Bay (BP 26.4% and operator) included an ongoing active infill
drilling programme with 111 new sidetracked wells, plus continued
development of the Greater Prudhoe Bay Satellite fields, which added
31 wells and production of 3 mboe/d in 2002.
-- The Northstar oil field (BP 98.8% and operator) completed its first
full year of production. We undertook remedial action to resolve
initial compressor start-up problems.
-- We are continuing to evaluate options to commercialize the Point
Thomson natural gas condensate field (BP 32%) on the Eastern North
Slope.
-- On August 16, 2002, an explosion and fire took place on the A Pad in
the Prudhoe Bay field resulting in an injury to an employee. The
explosion was caused by thermal expansion, which caused the outer
annulus pressure in the well to exceed normal operating pressures, as
opposed to being caused by corrosion or other damage. A third party
expert examined the casing and determined the pressure reached to be
about 7,700 pounds per square inch (psi), which exceeded the casing's
original rating of 5,380 psi. As a precautionary measure, 137 wells
with high annular pressures were taken out of production, and were not
brought back on line until enhanced procedures were developed and
implemented. Over 90 wells have been returned to production after
passing inspection. The remainder have not yet been returned to
production pending further engineering review. We paid a fine of
$6,300 to the US Occupational Safety and Health Administration on
February 21, 2003.
United Kingdom
We are the largest producer of both oil and natural gas in the UK. In 2002,
total crude oil production was 461 mb/d, a 5% decrease on 2001, and gas
production was 1,550 mmcf/d, a 9.5% decrease on 2001. The North Sea is a mature
basin and this reduction was driven by natural decline. In addition, an
operational problem on the Schiehallion Floating Production Storage and
Offloading (FP50) vessel resulted in a 27 day production outage in the third
quarter of 2002. Our activities in the North Sea are focused on production
optimization and cost efficiencies. This is delivered through proactive
reservoir management, including progression of new developments and new
production start-ups, the majority of which are tie backs to existing
infrastructure, and application of new technology to existing fields. Our
development expenditure in the UK was $895 million in 2002 compared with $930
million in 2001.
Significant activities in 2002 included the following:
Page 31
New Developments
-- In 2002, all major construction contracts were awarded for the Clair
field Phase 1 development (BP 28.6% and operator) and fabrication was
initiated. Clair is currently one of the largest undeveloped field on
the UK Continental Shelf (UKCS), with start-up scheduled in 2004.
New Production
New fields which started production in 2002 included:
-- The Juno Project comprises the development of 5 offshore gas fields;
BP has an interest in two of these -- Wollaston and Whittle (BP 35.5%
and operator). The Wollaston well was drilled and completed in record
time for the region and the Whittle well exceeded the production rate
forecast by optimization of drilling location and fluid systems.
Production commenced in December 2002.
New production from subsea wells tied back to existing facilities included:
-- The Mirren (BP 46%) and Madoes (BP 38%) fields began production in the
fourth quarter following tie-backs to the ETAP platform.
-- The Maclure field (BP 33.3% and operator) tie-back to the non-operated
Gryphon field started production in July 2002.
-- The Alba Extreme South development (BP 16%) was tied back to the Alba
North platform and came on stream in September 2002.
-- The Boyle field (BP 22% and operator) was developed through the
existing Davy field facilities and achieved first production in
October 2002.
New Technology
New and innovative applications of technology were applied to many of our
existing fields in the North Sea, to mitigate volume decline and increase
ultimate recoveries, examples of which include:
-- Foinaven is the largest BP net producing field in the UKCS. In 2002
production increased by 30% on 2001, from Foinaven (BP 72% and
operator) and East Foinaven (BP 43%) fields. This followed completion
of the 2nd phase of development drilling and debottlenecking activity.
In addition, a new integrated system model was developed to optimize
all production, gas lift and water injection.
-- A new yearly total production record of 43 mboe/d (BP net share) was
achieved from West of Shetland fields Schiehallion (BP 33% and
operator) and Loyal (BP 50% and operator) due to completion of
development drilling in Schiehallion and 2 new wells in the Loyal
field. During 2002, the gross production through the FPSO grew by 33%
on 2001 to 160 mb/d following the tie-in of the new wells. Export of
natural gas from Foinaven, East Foinaven, and Schiehallion to Magnus
through BP's newly constructed West of Shetland Pipeline System began
in the third quarter.
-- A Mid Life Compression Project was completed on the Everest field (BP
21% and operator) to extend plateau production and increase
recoverable reserves. The additional compression should enhance gross
export capability by 20 mmscfd.
-- The Enhanced Oil Recovery (EOR) project on the Magnus field (BP 85%
and operator) was completed and successful injection of West of
Shetland gas into the Magnus oil reservoir began in October, thereby
improving recovery of un-swept oil.
Page 32
-- In 2002, Bruce field (BP 37% and operator) successfully completed the
two longest reach (17,402 feet and 17,560 feet) Through Tubing Rotary
Drilled wells in the BP portfolio. A new ocean bottom cable seismic
survey was shot over part of the field to assist the development of
future drilling.
-- The Shearwater Project (BP 27.5%) saw the completion of remedial work
on three wells. As a result of the difficulties encountered, a full
field technical review was undertaken and a reserve write down taken
during the year. This, together with other works on the topsides to
overcome pipework cracking and flare tip issues, allowed the field to
produce at rates close to design capacity through the second half of
2002.
To further maximize the value from our existing mature fields we have
completed the following activities:
-- In the fourth quarter of 2002, BP completed a partial renegotiation of
the gas sale from the Sean field, (BP 50%) which was otherwise solely
dedicated to Centrica until 2011.
-- In 2002, a series of small asset swaps were completed to realign BP's
interest in the non-operated Braes complex of fields. This brought
BP's equity up to 30%. During 2002, the agreements governing the
offtake of gas from the Braes fields were renegotiated.
-- The NW Hutton field (BP 25.8% and operator) began preparation for
decommissioning in July 2002, following cessation of production. The
well decommissioning programme is ongoing, combined with engineering
studies to determine the best method to remove the facility.
-- All but 1% of BP's working interest was sold and operatorship was
transferred in the Thistle field (BP 81.7% and operator) effective
January 1, 2003. Upon economic depletion, the operator will return the
field to BP for decommissioning.
Rest of Europe
Norwegian production increased in 2002, mainly as a result of a full year
production from the Tambar field (BP 55% and operator), which came on stream in
July 2001. During the year BP acquired a further 5% interest in Gyda bringing
BP's share to 61%. The Draugen field (BP 18.4%) experienced initial water
breakthrough although new wells in Garn West and Rogn South have mitigated the
decline.
Our operations in the Netherlands primarily comprise gas storage services
delivered from the Peak Gas Installation to assist in meeting peak demand
requirements. This installation has a capacity of 17,000 mmcf and is capable of
withdrawing 1,270 mmcf/d.
Rest of World
In the Rest of World, areas of oil production in 2002 were Abu Dhabi,
Algeria, Angola, Argentina, Australia, Azerbaijan, Bolivia, Canada, China,
Colombia, Egypt, Indonesia, Pakistan, Russia, Sharjah, Trinidad, Venezuela and
Qatar.
The largest part of our share of natural gas production in 2002, in the
Rest of World, came from Trinidad and Tobago and from Indonesia, with the
remainder from Argentina, Australia, Bolivia, Canada, China, Colombia, Egypt,
Pakistan, Vietnam and Sharjah.
Page 33
Significant activity in Rest of World during 2002, included:
Canada
-- In Canada our 2002 production was 105 mboe/d, down 12% from 2001,
mainly due to natural field declines. Natural gas makes up 85% of
Canada's production. During 2002, we drilled 50 wells (gross), 39 of
which were operated by BP. In late 2002 we started up our Ojay
production in Northeastern British Columbia, which was producing 15
mmcf/d of natural gas at year end.
Caribbean and Latin America:
-- In Trinidad, gas sales increased by 22% and crude oil production
increased by nearly 40%. The increase in natural gas sales was
principally driven by the successful commissioning of Atlantic LNG
Train 2 (50% BP supply) in the third quarter 2002, as well as
expansion of the domestic sales contract with the National Gas Company
of Trinidad and Tobago. During the year, BP completed the construction
of the 48-inch offshore 'Bombax' gas pipeline, and successfully
installed and commissioned the Kapok facility in anticipation of Train
3 commissioning (75% BP supply) in 2003.
-- In Venezuela our four base assets are reactivation projects consisting
of two operated properties and two non-operated properties under
operating fee agreements to produce oil for the state oil company,
Petroleos de Venezuela S.A. (PDVSA). During the year, as a result of
the Veba transaction, the Cerro Negro asset was added to the
portfolio. As part of this transaction we have entered into a sales
agreement with Petro-Canada for the Cerro Negro asset and we have been
seeking resolution of the outstanding approvals in order to complete
the sale. As a result of a loss of reservoir pressure, reserve write
downs in LL652 and Boqueron were taken during the year. The Venezuelan
National strike action began to impact production by mid-December
2002. In January 2003, PDVSA started to slowly ramp up production and
by mid-March 2003, BP's production was approaching pre-strike levels.
-- The Colombian activity is made up of mature producing assets
(Cusiana/Cupiagua fields, BP 19%), assets under appraisal/development
(Recetor (BP 40%) and Florena/Pauto (BP 50%) fields). Decline in the
mature producing assets has been compensated by well work and new
production coming from the appraisal/development areas which now
account for 40% of the production. A facility expansion will allow
Florena and Pauto to further increase production during 2003. Phase I
development of the Recetor extension of Cupiagua field was
successfully completed and Phase II has commenced.
-- In Argentina and Bolivia, activity is conducted via our participation
in Pan American Energy (PAE) (BP 60%). In addition, PAE in turn owns
50.001% of Empresa Petrolera Chaco, a Bolivian oil and gas company.
In 2002, oil production increased by around 7% over 2001, largely as
a result of a major drilling programme in Golfo San Jorge. Gas
production increased by 6% over 2001. The significant increase arose
in Cerro Dragon and in the Northwest Basin, where new treatment plants
were completed and extended respectively.
Despite a severely depressed economy in Argentina, PAE was successful
in increasing its natural gas market share from 12% to 13% during
2002. PAE also has interests in NGL plants, oil and natural gas
pipelines, electricity generation plants, and other midstream
infrastructure.
Page 34
Africa
Angola
Angola is one of our five new profit centers where progression of several
key projects provides the foundation for volume growth over the next few years.
These projects include the following activities:
-- The ramp up of the Girassol field in Block 17 (BP 16.7%) was
successful, achieving plateau production within three months of field
start-up. The Jasmim project, a tie-back to the Girassol hub,
commenced construction in the first quarter of 2002.
-- In Block 15 (BP 26.7%), development activities progressed on Kizomba
A, expected to start up by late 2004. During the year Xikomba and
Kizomba B development projects commenced.
-- In Block 18 (BP 50% and operator), work has continued on the Greater
Plutonio development, with front-end engineering and design completed
in the fourth quarter of 2002.
-- BP is participating in studies to evaluate gas solutions, as part of
the Angola LNG project. (BP 12%).
Egypt
-- In Egypt, the Gulf of Suez Petroleum Company (GUPCO), a joint
operating company with BP and the Egyptian General Petroleum
Corporation, carries out our oil production operations. GUPCO operates
seven production-sharing contracts in the Gulf of Suez and Western
Desert, encompassing more than forty fields. New start-ups included
Esma, North Razzak and Edfu.
-- Gas production in Egypt grew 35% with Ha'py (BP 50%) and Baltim (BP
50%) and Temsah (BP 50%) fields ramping up and Akhen field (BP 50%)
contributing from the third quarter of 2002. In 2002, BP's entitlement
gas production reached 256 mmscfd, underpinned by agreements to supply
to the domestic Egyptian market from these and other Nile Delta
fields.
-- BP has a 33% interest in a joint venture United Gas Derivatives, which
operates the Med NGL project. The project involves the construction of
a 1.1 bcf/d NGL plant, progressed in 2002.
Algeria
-- In Algeria, BP and the Algerian state company, Sonatrach, continued to
progress the development of the In Salah project (BP 65%). The first
stage comprises the development of four of the seven deep Saharan
natural gas fields expected to supply the fast-growing markets of
Southern Europe.
-- In November 2002, BP and Sonatrach reached agreement to expand the In
Amenas (BP 100%) project scope, enhancing the plant size from two to
three trains in the development of the gas condensate field. The In
Amenas Engineering, Procurement and Construction contract was been
awarded to KBR/JGC engineering company.
-- Following completion of a technical reassessment in September 2002, a
reserve write down was made on Rhourde El Baguel (BP 60%).
Page 35
Middle East and Pakistan
-- Production in the Gulf States was dominated by the production
entitlement of associated undertakings in Abu Dhabi where we have
equity interests of 9.5% and 14.7% in onshore and offshore
concessions. In 2002 production in Abu Dhabi was down from 2001 as a
result of OPEC cuts.
-- Sharjah natural gas production was down 16% on 2001, although the
decline in 2002 was moderated by plant modifications and successful
drilling activities in 2001.
-- In Qatar, BP divested its interest in the Al Rayaan development.
-- The operator continues to progress negotiations on Core Venture 1 in
Saudi Arabia, in which BP has a 25% stake.
-- In Iran we continue to evaluate a number of potential opportunities
including the Ahwaz Bangestan redevelopment and a South Pars LNG
project. At this stage, no agreements have yet been concluded that
commit BP to any significant investments in Iran.
-- In Pakistan, BP is the largest foreign operator producing 47% of the
country's oil and 8.5% of its natural gas on a gross basis. In 2002,
production was up 42% compared to 2001 as the Company has deepened its
interest in the Badin field. During 2002 we disposed of our interest
in the Qadirpur field to KUFPEC, for $80.6 million.
Azerbaijan and Russia
Azerbaijan
-- BP, as operator of the Azerbaijan International Operating Company
(AIOC), manages and has a 34.1% interest in the Azeri-Chirag-Gunashli
(ACG) oil fields under the Caspian Sea, offshore Azerbaijan. In 2002,
ACG production grew from the Chirag 1 platform. The staged development
of the full field made good progress with execution of Central Azeri
projects (previously referred to as ACG Phase 1). The second phase of
development on West and East Azeri commenced on 1 September 2002 for
which the following contracts were awarded:
-- CWP Topsides to AMEC and Tekfen Azfen
-- West Azeri/East Azeri Topsides to McDermott
-- West Azeri/East Azeri Accommodation to Emtunga
The Engineering Procurement Contract for ACG Phase 3 was awarded to
AMEC in September 2002.
-- A staged plan has been developed for the Shah Deniz natural gas field
(BP 25.5% and operator). Progress was made on partner, government,
transportation and related agreements.
Russia
-- In Russia, we acquired an additional 15% plus 1 share interest in
Sidanco in April 2002, raising our equity to 25% plus 1 share, in line
with our previous voting rights. BP seconded personnel hold a number
of the senior management positions and a BP executive acts as Chairman
of the Sidanco Board of Directors. Production growth exceeded the
equity increase, rising 270% to 74 mb/d compared with 2001. The
interest in Sidanco will become part of our new Russian joint venture,
TNK-BP.
Page 36
Far East and Australia
-- In Indonesia, BP is the largest supplier of natural gas to Java. In
addition, BP participates in Indonesia's LNG exports through its
Sanga-Sanga Production Sharing Contract (PSC) holding (38% BP). BP
holds 26% directly and 12% via its associate company VICO. Sanga-Sanga
delivers 30% of the total gas feed to the Bontang LNG plant.
-- In China, the Yacheng field (BP 34% and operator) supplies 100% of the
natural gas supply for power generation into Hong Kong where it is
sold to Castle Peak Power Company under a long-term contract. Some
natural gas and all the crude oil is piped to Hainan Island where the
natural gas is sold to the Fuel and Chemical Company of Hainan also
under a long-term contract. In 2002 the remaining four platforms (out
of a total of six platforms) on the QHD oil field (BP 24.5%) were
installed and commissioned allowing the field to reach plateau late in
2002.
-- In Vietnam, construction, installation and commissioning of the
onshore/offshore production and transportation system was completed
for the Lan Tay Platform (BP 35% and operator). In November 2002 first
gas was produced. Lan Tay gas is sold under a long-term agreement for
electricity generation in Southern Vietnam.
Midstream Activities
Oil and Natural Gas Transportation
The Group has direct or indirect interests in certain crude oil
transportation systems, the principal ones of which are the Trans Alaska
Pipeline System (TAPS) in the USA and the Forties Pipelines System (FPS) in the
UK sector of the North Sea. We also operate the Central Area Transmission System
(CATS) for natural gas in the UK sector of the North Sea.
BP, as AIOC operator, manages and holds a 30.1% interest in the
Baku-Tbilisi-Ceyhan (BTC) oil pipeline currently under construction. AIOC
operates the Western Export Route Pipeline between Azerbaijan and Black Sea
coast of Georgia and the Azeri leg of the Northern Export Route Pipeline between
Azerbaijan and Russia.
Our onshore US crude oil and product pipelines and related transportation
assets are included under 'Refining and Marketing' in this item. Revenue is
earned on pipelines through charging tariffs. Our gas marketing business is
described under 'Gas, Power and Renewables' in this item.
Significant activity in oil and natural gas transportation during 2002
included:
Alaska
-- BP owns a 46.9% interest in TAPS, with the balance owned by five other
companies. TAPS transported production from Prudhoe Bay and the other
North Slope fields averaging 1,004 mb/d.
There are a number of unresolved protests regarding tariffs charged
for shipping oil through the Northstar Pipeline (BP 98.8% and
operator) and TAPS. These protests were filed between 1994 and 2002
with the Federal Energy Regulatory Commission and the Regulatory
Commission of Alaska (RCA). The RCA recently issued an Order requiring
refunds to be made to shippers of intra-state crude oil through TAPS.
BP has appealed this Order to the Alaska Superior Court.
The use of US-built and US-flagged ships is required when transporting
Alaskan oil to markets in the USA. In accordance with this, BP America
Inc. has a chartered fleet of 10 US-flagged tankers to transport
Page 37
Alaskan crude oil to markets. 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 Environmental Protection -- Marine Oil
Spill Regulations within Item 4. BP has contracted for the delivery of
four 1.3 million-barrel-capacity, double-hull tankers for use in
transporting North Slope oil to West Coast refineries. The ships are
being constructed by NASSCO in San Diego with deliveries in years
2004, 2005 and 2006.
North Sea
-- FPS in the UK (BP 100%) is an integrated oil and NGL transportation
and processing system that handles production from over 40 fields in
the Central North Sea. The system has a capacity of more than 1 mmb/d,
with average throughput in 2002 at 820 mb/d.
-- BP operates and has a 29.5% interest in 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 bcf/d to a natural gas
terminal at Teesside, Northeast England. CATS offers natural gas
transportation services or transportation and processing via two 600
mmcf/d processing trains. In 2002, throughput was 1.7 bcf/d.
Asia (including the former Soviet Union)
-- For the BTC oil pipeline, detailed engineering was completed in mid
2002 and the project was approved for construction by partners on 1
August. BP diluted its equity in the project to 30.1% in 2002,
consistent with its upstream throughput requirements. Extensive
consultations have been carried out with landowners along the pipeline
corridor, affected communities, national government institutions, and
other interested parties during 2002 to gain input into the project.
Environmental and Social Impact Assessments have been approved in
Azerbaijan, Georgia and Turkey. Land acquisition has commenced in all
three countries and follows World Bank Policy guidelines. The pipeline
crosses no IUCN category I-IV reserves and the route avoids the need
for any resettlement of population.
-- Through the LukArco Joint Venture BP holds a 5.75% interest in the
Caspian Pipeline Consortium (CPC) pipeline. CPC is a 1,510-kilometre
pipeline from Kazakhstan to the Russian port of Novorossiysk. The
pipeline has an initial capacity of 28.2 million tonnes (approximately
225 mmboe) a year and carries crude oil from the Tengiz field (BP
2.3%). In addition to our interest in LukArco, we hold a separate
0.87% interest in CPC.
Gulf of Mexico
-- Construction continued on the Mardi Gras pipeline system (BP
approximately 65% and operator). When complete, the network of
pipelines will extend, in total, more than 450 miles, and lie in
waters of greater than 7,000 feet deep. It will be the largest
capacity deepwater pipeline ever built.
Liquefied Natural Gas
Within BP, Exploration and Production is responsible for the supply of LNG
and Gas, Power and Renewables is responsible for the subsequent marketing and
distribution of LNG (see details under 'Gas, Power and Renewables -- New Market
Development and LNG' in this item).
Significant activity during 2002 included the following:
-- We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction
Company, which in 2002 supplied 5.3 million tonnes of LNG, down 3% on
2001.
Page 38
-- In Australia the North West Shelf Venture (BP 16.7%) was successful in
securing a long-term LNG supply contract, to supply the first 3.2
mmtpa for Guangdong terminal commencing in 2006. LNG Train 4 is
progressing both on schedule and budget.
-- In Indonesia, VICO is a jointly owned operating company held 50:50 by
BP and ENI/Lasmo. It operates the Sanga-Sanga PSC in East Kalimantan
on behalf of BP (38%) and ENI/Lasmo, as well as CPC (Taiwan) and a
consortium of JAPEX, Osaka Gas, JNOC, Nippon Mining, and Nissho Iwai.
In addition, we have interests in the Wiriagar (BP 38% and operator,
post-CNOOC sale), Berau (BP 48% and operator) and Muturi (BP 1%,
post-CNOOC sale) PSC's in Northwest Papua. These PSCs will provide the
natural gas feed to the Tangguh LNG project, which is expected to
become the third LNG centre in Indonesia.
In September 2002, an agreement was signed for the supply of 2.6
million tonnes per year of LNG to Fujian. Concurrent with the signing
of the LNG supply agreement, BP entered into a Heads of Agreement with
CNOOC to sell 12.5% of BP's 49.7% interest in Tangguh. The government
of Indonesia approved the project's environmental and social impact
assessment in October 2002. Evaluation of the technical bids for the
LNG Plant was also completed in October. In addition, front-end
engineering and design work was completed for the pipelines and
platforms in the fourth quarter of 2002.
-- In Trinidad, Atlantic LNG Train 2 (BP 42%) was successfully
commissioned in the third quarter, with first LNG sales taking place
in August. Front-end engineering and design for LNG Train 4 (4.8
million tonnes per annum) was completed, and negotiations with
partners and the government of Trinidad and Tobago are progressing.
-- In Trinidad, we announced our agreement to own a 37% share in the
Atlas methanol plant, with Methanex, the Canadian operator, holding
the remainder. BP, through its customer NGC, will supply 100% of the
natural gas demand for the plant. Plant construction continues with
first sales planned in first quarter of 2004.
Page 39
GAS, POWER AND RENEWABLES
The strategic purpose of the Gas, Power and Renewables segment is to
maximize the value of BP's gas through marketing, to enhance the value of BP's
natural gas liquids production and to build a profitable renewables business. On
January 1, 2002, the solar, renewables and alternative fuels business activities
were transferred to the Gas and Power business from Other Businesses and
Corporate. To reflect this transfer, Gas and Power was renamed Gas, Power and
Renewables from the same date and the financial information for 2000 and 2001
has been restated.
The segment is organized into four main activities: marketing and trading;
natural gas liquids (NGL); new market development and LNG; and solar and
renewables.
Years ended December 31,
--------------------------------
2002 2001 2000
------ ------ -------
($ million)
Turnover ....................................................... 37,357 39,442 21,203
Total replacement cost operating profit ........................ 354 488 532
Total assets.................................................... 6,927 5,775 6,997
Capital expenditure and acquisitions............................ 408 492 376
We seek to maximize the value of our gas by targeting higher value customer
segments in selected markets and to optimize supply around our physical and
contractual assets. Marketing and trading activities are focused on the
relatively open and liberalized natural gas and power markets of North America,
the United Kingdom and certain parts of continental Europe. Some elements of
long-term natural gas contracting activity are also still included within the
Exploration and Production business segment.
During 2002 we sold our 25.5% interest in Ruhrgas, which had been announced
in 2001 as part of the Veba deal.
Our NGLs business is engaged in the processing, fractionation and marketing
of ethane, propane, butanes and pentanes extracted from natural gas. Our NGL
activity is underpinned by our upstream asset base and serves markets for both
chemicals and clean fuels and also supplies BP's chemicals and refining
activities.
New market development and LNG activities involve developing opportunities
to capture sales for our upstream natural gas resources, and are conducted in
close collaboration with the Exploration and Production business. Our strategy
is to capture a disproportionate share of growth in the international demand for
natural gas and is focused on markets which offer significant prospects for
growth. These include the USA, Canada, Spain and many of the emerging markets of
the Asia Pacific region, notably China, where we believe there could be
substantial growth in demand. For our undeveloped gas, we believe the key is to
gain markets ahead of supply with a longer-term aim of allowing gas resources to
move into the market with the same ease that oil does today. Our LNG activities
involve the marketing of BP and third party LNG.
Our solar and renewables business activities include the development,
production and marketing of solar panels and the development of wind farms on
specific company sites.
Our other activities include several gas-fired power generation projects,
where our principal focus is on projects that monetize our equity natural gas
and/or reduce Group power costs and reduce overall emissions.
Page 40
Marketing and Trading Activities
Our gas marketing and trading activities are concentrated in the markets of
North America and the United Kingdom. Gas sales volumes have increased from 18.8
bcf/d in 2001 to 21.6 bcf/d in 2002. Most of this growth was realized in the USA
and Canada. Canada volumes are reported in the Rest of World volumes.
Years ended December 31,
--------------------------------
Gas sales volumes (a) 2002 2001 2000
------ ------ ------
(million cubic feet per day)
UK............................................................. 2,372 2,641 2,526
Rest of Europe................................................. 399 213 178
USA............................................................ 9,315 8,327 6,524
Rest of World.................................................. 9,535 7,613 5,243
------ ------ ------
Total.......................................................... 21,621 18,794 14,471
====== ====== ======
----------
(a) Includes marketing, trading and supply sales.
Our policy toward natural gas price risk is described in Item 11 --
Quantitative and Qualitative Disclosures about Market Risk.
North America
BP is one of the leading marketers and traders of natural gas in North
America, the world's largest natural gas market, a business which has been built
on the foundation of our position as the continent's leading producer of gas.
Our North American total natural gas sales volumes have grown from 9.7 bcf/d in
2000 to 13.4 bcf/d in 2001 and to 16.1 bcf/d in 2002. Of these sales volumes,
3.6 bcf/d was supplied from BP upstream producing operations in 2000, increasing
to 4.1 bcf/d in 2001 and 4.0 bcf/d in 2002.
Our North American natural gas marketing and trading strategy seeks to
provide unconstrained market access for BP's equity gas, increase gross margin
through targeting higher value customer segments and optimizing around our
network of connected assets to reduce cost of goods sold. These assets could
include those owned by BP and those contractually accessed through agreements
with third parties.
United Kingdom
The natural gas market in the UK is significant in size and is one of the
most progressive in terms of deregulation when compared with other European
markets. BP is one of the largest producers of natural gas in the UK. Our total
natural gas sales volumes in the UK were 2.4 bcf/d in 2002, 2.6 bcf/d in 2001
and 2.5 bcf/d in 2000. Of these volumes 1.6 bcf/d (2001 1.7 bcf/d and 2000 1.7
bcf/d) were supplied from BP's upstream producing operations. Some of the
natural gas is sold under long-term natural gas supply contracts to customers
such as Centrica, the largest distributor of gas in the UK. However, the
majority of natural gas sales are to commercial and industrial customers, power
generation companies and via long-term supply deals with other gas wholesalers.
We also sell physical natural gas on the UK spot market.
We have a 10% interest in the Interconnector, a 1.9-bcf/d, 240-kilometre,
40-inch diameter sub-sea natural gas pipeline between Bacton in the UK and
Zeebrugge in Belgium, which effectively links the natural gas markets of the UK
and continental Europe.
In June 2002 we sold our contract energy management business to Elyo.
Page 41
Rest of Europe
We are building a natural gas and power marketing and trading business in
Europe. Our interest in the European market is driven by the size and growth
potential of the market, deregulation and the proximity of BP natural gas
supplies.
In Europe our main marketing activities are in Spain. The Spanish natural
gas market has continued to grow and has liberalized at a faster rate than
required by European law, with full market opening effective as from January
2003. Over the last two and a half years in Spain we have continued to build our
position as the leading new entrant, maintaining our position as number two
behind the incumbent Gas Natural. In July 2002 we purchased 5% of the shares in
Enagas, the owner and operator of the majority of the Spanish grid and Spain's
three existing regas terminals.
Natural Gas Liquids
Years ended December 31,
--------------------------------
NGL sales volumes 2002 2001 2000
------ ------ ------
(thousand barrels per day)
UK..................................................... -- -- --
Rest of Europe......................................... -- -- --
USA.................................................... 208 221 154
Rest of World.......................................... 202 189 195
------ ------ ------
Total.................................................. 410 410 349
====== ====== ======
BP is one of the largest marketers of NGLs in North America and considers
NGLs as an integral part of the overall natural gas value chain. A significant
portion of BP's NGLs are marketed on a wholesale basis under annual supply
contracts that provide for price redetermination based on prevailing market
prices.
NGLs are also supplied to our chemical and refining activities. We operate
natural gas processing facilities across North America with a total capacity of
8.3 bcf/d. We own or have an interest in fractionation plants in Canada and the
United States.
New Market Development and LNG
Our new market development and LNG activities are focused on developing
worldwide opportunities to capture international natural gas sales for our
upstream natural gas resources.
BP's major existing LNG supplies are from Trinidad and Tobago, ADGAS in Abu
Dhabi and the North West Shelf in Australia. We also supply gas (from VICO) to
the Bontang LNG project in Indonesia. Additional LNG supplies and gas
monetization are being pursued through expansions of existing LNG plants in
Trinidad and Tobago, the North West Shelf in Australia, and greenfield
developments such as Tangguh in Indonesia.
In Trinidad, a second LNG train commenced operations in August 2002, with
initial deliveries to Lake Charles, Louisiana. A third train is scheduled to
start-up in 2003. In the Spanish market, construction continued on the
integrated LNG regasification and power generation facility at Bilbao (BP 25%),
which should start-up in 2003. BP has secured 250 mmcf/d regasification capacity
in Cove Point, Maryland that should commence operations in 2003. We plan to
deliver LNG from Trinidad to the Cove Point regasification facility upon
start-up. Short-term contracts for LNG supply were signed with ADGAS and Qatar
in October 2002. These LNG supplies will allow us to further optimize our
Atlantic LNG marketing business.
Page 42
In the rapidly growing South China market, BP continued to develop a
leading gas supply position. Development of the Guangdong LNG Terminal and
Trunkline project (BP 30%) continued and bids were solicited for gas supply
totalling 3.3 million tonnes per annum of LNG. The Australia North West Shelf
consortium (BP 16.7%) was selected as the winner of this initial sales contract,
which was signed in October, 2002 and is due to commence delivery in 2006.
The Chinese government announced plans for a second LNG terminal, in Fujian
province, and an agreement was signed in September 2002 to supply 2.6 million
tonnes per annum to the terminal from Indonesia's Tangguh natural gas project
(BP 37.2% from January 1, 2003).
In November 2002, BP took delivery of the first of three new leased LNG
ships from Samsung Heavy Industries in Korea. Two more LNG ships should be
delivered during 2003. These ships will be employed in the Asia-Pacific and
Atlantic trades, delivering from LNG suppliers to market positions established
by BP and others.
Solar and Renewables
Global market trends demonstrate a move towards greener energy sources,
including solar and wind. BP intends to shape and develop this market from a
base as one of the world's leading solar companies. In November 2002 BP
announced it would concentrate on its key markets supported by growth in
worldwide manufacturing of its crystalline-based products, and would cease
manufacturing its thin film solar modules.
Our solar energy business in 2002 grew in excess of 20% as sales reached a
total of 67 megawatts (MW) of solar panels generating capacity (2001, 55 MW). To
expand the market for solar, we initiated plans to extend the brand directly
into residential and consumer markets with a launch in January 2003 in
California.
Major projects in 2002 included the completion of a $10 million project to
power 1,852 schools in remote areas of Brazil and a $3 million project to power
telecommunication systems in remote areas of Peru, benefiting 3 million people.
BP and partners have also been selected to supply an on-grid, solar power system
to China's Shenzhen Citizen Center, a new building providing municipal
facilities.
We are building expertise in wind energy and implementing wind projects on
selected BP sites. In 2002 we announced the start-up of our 22.5 megawatt wind
farm at the Nerefco oil refinery in the Netherlands, which provides electricity
to the refinery and the local grid. The refinery and the wind farm are jointly
owned with ChevronTexaco (BP 69%).
Other Activities
We participate in power projects that support the marketing and sale of our
natural gas and in cogeneration projects on certain BP refining and chemical
manufacturing sites. We currently have two major power generation construction
projects underway: the LNG regasification and power generation facility at
Bilbao (BP 25%) and a 570 MW cogeneration plant as part of a 50:50 joint venture
with Cinergy Solutions, Inc. at Texas City,Texas, which is BP's largest refining
and petrochemical complex. BP will supply natural gas to the Texas City plant
and will use the excess generation capacity to support power marketing and
trading activities.
During the year our 400 MW gas-fired power plant at Great Yarmouth in the
UK completed its performance and grid connection tests. We are operating the
plant and selling electric power, with BP providing the natural gas to the
plant.
In alternative fuels, we are exploring market opportunities for hydrogen
fuel cells through participation in various industry projects and organisations
promoting fuel cells for transport and stationary power.
Page 43
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. BP markets our products in over 100
countries. We operate primarily in Europe and North America, but also market our
products across Australasia and in parts of South East Asia, Africa and Central
and South America.
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Turnover (a)........................................................... 125,836 120,233 107,883
Total replacement cost operating profit................................ 872 3,573 3,486
Total assets........................................................... 55,815 43,553 46,288
Capital expenditure and acquisitions................................... 7,753 2,415 8,693
($ per barrel)
Global Indicator Refining Margin (b)................................... 2.11 4.06 4.22
----------
(a) Excludes BP's share of joint venture turnover of $415 million in 2002, $403
million in 2001 and $13,112 million in 2000.
(b) The Global Indicator Refining Margin is the average of seven regional
indicator margins weighted for BP's crude refining capacity in each region.
Each regional indicator margin is based on a single representative crude
with product yields characteristic of the typical level of upgrading
complexity.
There are four areas of business in Refining and Marketing: Refining,
Retail, Lubricants and Business to Business Marketing. Our strategy is to grow
through focused investment in key assets and market positions. In all areas we
aim for greater operational efficiency and, at the same time, we seek to improve
our asset portfolio. The acquisition of Veba's marketing and refining operations
provides an important addition of high quality assets to our operations.
Refining and Marketing manages a portfolio of assets that we believe are
competitively advantaged across the chain of downstream activities. Such
advantage may derive from several factors, including location, operating cost
and physical asset quality.
We are one of the leading refiners of gasoline and hydrocarbon products in
the USA, Europe and Australia. We have significant retail and business to
business market positions in the USA, UK, Germany and the rest of Europe,
Australasia, Africa and South East Asia and we are enhancing our presence in
China and Mexico.
BP acquired Veba's retail and refining assets in Germany and Central Europe
in 2002. The Veba acquisition makes BP the retail market leader in Germany and
Austria, and substantially strengthens BP's position in Poland and in several
other Central European countries. Veba's retail stations are branded Aral and BP
is in the process of rebranding its BP branded stations in Germany to the Aral
brand. Veba has interests in five refineries in Germany. As a condition of the
approval of the acquisition of Veba, BP was, amongst other things, required to
divest approximately 4% of its retail market share in Germany and a significant
portion of its Bayernoil refining interests. The $146 million sale of 494 retail
sites in the northern and northeastern part of Germany to PKN Orlen, announced
in December 2002 and the $394 million sale of retail and refinery assets in
Germany and Central Europe to OMV announced in February 2003 will complete the
divestments required.
Page 44
BP continues to optimize its Downstream portfolio through selective
dispositions. In 2002 BP divested its Yorktown, Virginia refinery, BP's equity
interest in the Colonial Pipeline, BP's Cyprus and Oman retail assets and
various small retail assets throughout the USA and Europe.
The number of employees at December 31, 2002 was 73,350, an increase of
approximately 8,750 from year-end 2001.
Refining
The Company's global refining strategy is to own interests in and to
operate advantaged refineries that provide supplies for its marketing operations
and/or are integrated with other parts of the Group's business. Refining's focus
remains continuing safe, reliable, and efficient operations of the refining
system and income growth.
For BP, advantaged refinery characteristics relate to the refinery's
position in relation to the market, the refinery's ability to support our clean
fuels strategy, and the value created through the integration with other parts
of the Group's business. Efficient operations are measured primarily using
regional refining surveys. The surveys assess our competitive position against
benchmarked industry measures such as costs per barrel. Investment in our
refineries is focused on maintaining our competitive position and developing the
capability to produce the cleaner fuels and the enhanced quality products that
meet our customers and the communities' requirements.
In line with the Company's global refining strategy, we completed the sale
of the Yorktown, Virginia refinery to Giant Industries, Inc. on May 13, 2002. We
have also announced our intention to sell our 33% equity interest in the
Singapore Refining Company (SRC). In February 2003 we announced the divestment
of a 45% interest in our Bayernoil refinery, as required in connection with the
acquisition of Veba.
Page 45
The following table summarizes the BP Group interests and crude
distillation capacities (at December 31, 2002):
Crude distillation
capacities (a)
Group interest(b) BP
Refinery % Total Share(c)
-------- -------------- ------ ------
UK Coryton* 100.00 172 172
Grangemouth* 100.00 205 205
----- -----
Total UK 377 377
----- -----
Rest of Europe
France Lavera* 100.00 218 218
Reichstett 17.00 84 14
Germany Bayernoil* 67.50 267 180
Gelsenkirchen* 50.00 266 133
Karlsruhe 12.00 308 37
Lingen* 100.00 87 87
Neuhof*+ 100.00 -- --
Schwedt 18.75 221 41
Netherlands Nerefco* 69.00 400 276
Spain Castellon* 100.00 110 110
Turkey Mersin* 68.00 100 68
----- -----
Total Rest of Europe 2,061 1,164
----- -----
USA
Califonia Carson* 100.00 260 260
Washington Cherry Point* 100.00 232 232
Indiana Whiting* 100.00 420 420
Ohio Toledo* 100.00 155 155
Texas Texas City* 100.00 470 470
----- -----
Total USA 1,537 1,537
----- -----
Rest of World
Australia Bulwer* 100.00 90 90
Kwinana* 100.00 139 139
New Zealand Whangerei 23.66 109 26
Singapore SRC* 33.00 288 95
Kenya Mombasa 17.00 90 15
South Africa Durban 50.00 182 91
----- -----
Total Rest of World 898 456
----- -----
Total 4,873 3,534
===== =====
----------
* Indicates refineries operated by BP.
+ Indicates lubricants refinery which does not have crude distillation
capacity.
(a) Gross rated capacity is defined as the maximum achievable utilization of
capacity (24-hour assessment) based on standard feed.
(b) BP share of equity, which is not necessarily the same as BP share of
processing entitlements.
(c) These are shown as BP share of capacities.
Page 46
The following table outlines by region the volume of crude oil and
feedstock processed by BP for its own account and for third parties, and for the
Group by other refiners under processing agreements. Corresponding BP refinery
capacity utilization data are summarized.
Years ended December 31,
---------------------------------
Refinery throughputs (a) 2002 2001 2000
-------- -------- ---------
(thousand barrels per day)
UK (b)................................................................. 389 364 324
Rest of Europe (b)..................................................... 918 663 602
USA.................................................................... 1,439 1,526 1,625
Rest of World.......................................................... 357 376 365
----- ----- -----
3,103 2,929 2,916
For BP by others....................................................... 14 14 12
----- ----- -----
Total.................................................................. 3,117 2,943 2,928
===== ===== =====
Refinery capacity utilization
Crude distillation capacity at December 31, (b) (c).................... 3,534 3,259 3,165
Crude distillation capacity utilization (d)............................ 91% 94% 95%
United States........................................................ 93% 95% 97%
Europe............................................................... 91% 94% 96%
Rest of World........................................................ 85% 93% 87%
----------
(a) Refinery throughput reflects crude and other feedstock volumes.
(b) Includes the BP share of the BP/Mobil joint venture until August 1, 2000.
(c) Gross rated capacity is defined as the maximum achievable utilization of
capacity (24 hour assessment) based on standard feed.
(d) Crude distillation capacity utilization is defined as the percentage
utilization of capacity per calendar day over the year after making
allowances for average annual shutdowns at BP refineries (i.e. net rated
capacity).
BP's 2002 refinery throughput increased in the rest of Europe compared with
2001, primarily due to the Veba acquisition. The decrease in the USA over the
same period is mainly due to the sale of the Yorktown, Virginia refinery.
Marketing
Marketing comprises three business areas: Retail, Lubricants and Business
to Business Marketing. We market a comprehensive range of refined oil products
worldwide. These products include gasoline, gasoil, marine and aviation fuels,
heating fuels, LPG, lubricants and bitumen.
Page 47
The following table sets out refined product sales by area. A significant
increase in sales was achieved in 2002 as a result of the Veba acquisition.
Years ended December 31,
---------------------------------
Sales of refined products (a) 2002 2001 2000
-------- -------- ---------
(thousand barrels per day)
Marketing sales:
UK(b)(c)............................................................. 253 266 256
Rest of Europe (b)................................................... 1,467 1,062 901
USA.................................................................. 1,874 1,866 1,783
Rest of World........................................................ 586 603 480
----- ----- -----
Total marketing sales (d).............................................. 4,180 3,797 3,420
Trading/supply sales (d)............................................... 2,383 2,409 2,103
----- ----- -----
Total refined products................................................. 6,563 6,206 5,523
===== ===== =====
($ million)
Proceeds from sale of refined products (b)............................. 87,520 82,241 74,239
----------
(a) Excludes sales to other BP businesses.
(b) Includes the BP share of the BP/Mobil European joint venture until August
1, 2000.
(c) UK area includes the UK-based international activities of Refining and
Marketing.
(d) Marketing sales are sales to service stations, end-consumers, bulk buyers,
jobbers and small resellers. Trading/supply sales are to large unbranded
resellers and other oil companies.
The following table sets out marketing sales by major product group:
Years ended December 31,
---------------------------------
Marketing sales by product 2002 2001 2000
-------- -------- ---------
(thousand barrels per day)
Aviation fuel.......................................................... 529 515 474
Gasolines.............................................................. 1,744 1,659 1,512
Middle distillates..................................................... 1,232 1,077 945
Fuel oil............................................................... 451 351 338
Other products......................................................... 224 195 151
----- ----- -----
Total marketing sales ................................................. 4,180 3,797 3,420
===== ===== =====
In marketing our aim is to grow gross margin by focusing on both volumes
and unit gross margin. We do this by growing our customer base, both in existing
and new markets, by attracting new customers and by covering a wider geographic
area. We also work to improve the efficiency of our operations through reducing
the cost of goods sold and improving our product mix. In addition, we recognize
that our customers are demanding a wider choice of fuels, particularly fuels
that are cleaner and more efficient. Through our integrated refining and
marketing operations we believe we are able to meet these customer needs.
During 2002 we continued implementation of our clean fuels initiative and
became the largest retailer in California to eliminate MTBE in all the gasolines
we sell.
Page 48
Retail
In retail, we differentiate between two distinct segments: a fuels segment
in which we supply fuel to retail customers through dealers and jobbers, and a
convenience segment, incorporating an integrated fuel and convenience store
offering, the operation of which will either be directly managed or franchised.
The strategic focus in this segment is to underpin or expand gross margin
through selective investment in fast growing convenience and emerging markets
and by driving efficiency in mature fuels markets. In order to achieve above
market growth, we plan to concentrate our investment primarily in additional
store space on existing real estate in our core metropolitan convenience
markets. During 2002, our retail sales grew 7% in stores we also operated in
2001, a similar rate to the previous year. Retail fuel volumes grew by 10%,
including the effect of the Veba acquisition.
Years ended December 31,
--------------------------------
Shop sales (a) 2002 2001 2000
-------- -------- ---------
($ million)
UK..................................................................... 527 458 357
Rest of Europe......................................................... 2,638 904 663
USA.................................................................... 1,585 1,510 1,251
Rest of World.......................................................... 421 362 353
----- ----- -----
Total.................................................................. 5,171 3,234 2,624
===== ===== =====
Direct-- managed....................................................... 1,869 1,650 1,397
Franchise.............................................................. 3,216 1,504 1,154
Shop alliances......................................................... 86 80 73
----- ----- -----
Total.................................................................. 5,171 3,234 2,624
===== ===== =====
----------
(a) Shop sales reported are sales through direct-managed stations, franchises
and the BP share of shop alliances and joint ventures. Sales figures
exclude sales taxes and lottery sales but include quick service restaurant
sales. The sales include the BP share of the relevant sales within the
BP/Mobil European joint venture until August 1, 2000.
Our retail network is concentrated in Europe and the USA, with established
operations in Australasia, South East Asia and Southern Africa as well. We are
developing networks in China, Mexico and Russia.
In 2002, we added approximately 3,200 service stations in Germany and
Central Europe as a result of the Veba acquisition to increase BP's worldwide
network to approximately 29,200 stations, most of them BP, Amoco, ARCO and Aral
branded. BP expects its total number of service stations to decline in future
years reflecting the continued optimization of the efficiency of our retail
network and the mandated divestments required for approval of the Veba
acquisition. The mandated divestments, which have been announced in December
2002 and February 2003, will result in the sale of about 800 retail sites in
Germany and Central Europe.
In 2002, we continued our rollout of BP Connect sites primarily in the UK
and USA as part of our retail strategy that builds on our advantaged locations,
strong market positions and brand. The BP Connect sites offer our customers
cleaner fuels, a wider range of services and a distinctive food offer. The new
BP Connects include new sites, razed and rebuilt sites, and extensive upgrading
and remodelling of some existing stations. At December 31, 2002 486 BP Connect
stations were open. In addition the number of stations with the new BP Helios
design increased by about 5,500 during 2002.
Page 49
We also continue to improve the efficiency of our retail asset network
through a process of regular review. Actions taken during 2002 have included
divesting sites and networks. Alongside this activity, we have continued to
upgrade existing sites and invest in new sites, principally in markets where we
believe there is growing demand for our full convenience offer.
At December 31, 2002, BP's retail network in the USA comprised
approximately 14,900 service stations of which approximately 10,500 were jobber
owned. Developments in the USA during 2002 included the strategic divestment of
349 service stations to concentrate our ownership of real estate in markets
designated for development of the convenience offer. In the USA, we opened 80 BP
Connect sites and increased the number of stations with the new BP Helios design
by approximately 2,100.
In the UK and the Rest of Europe, BP's network comprised about 10,500
service stations at December 31, 2002. In 2002 we opened 57 BP Connect sites in
Europe with the majority being in the metropolitan London area. The number of
stations throughout Europe which use the new BP Helios design grew by about
3,200. The Veba acquisition has significantly strengthened our retail position
in Germany and Central Europe making BP the market leader in Germany and Austria
by adding over 2,800 stations in Germany and 155 stations in Austria. In Central
Europe, the Veba deal has added over 130 stations in the Czech Republic,
Slovakia and Hungary. The combination of the BP and Veba network in Poland makes
BP the largest foreign oil company in Poland with over 275 stations. In Russia,
we continued to expand our retail network by adding 5 stations in 2002. Our 39
stations in the Moscow metropolitan area are expected to be part of TNK-BP, our
Russian joint venture. In 2002 we sold our network of 70 service stations and
several other assets in Cyprus to Hellenic Petroleum.
At December 31, 2002 BP's retail network in the rest of the world comprised
some 3,800 service stations. Our established networks are primarily in
Australia, New Zealand, Southern Africa and South East Asia. BP is growing in
China through two strategic alliances. BP's joint venture with PetroChina in
Guangdong Province in the coastal region of China had 320 stations at December
31, 2002. BP has agreed in principle with Sinopec to form a second alliance
through a joint venture to acquire, revamp or build 500 fuels service stations
in the Zhejang Province, East China. The dual-branded service stations will sell
gasoline produced by Sinopec and sell other petroleum products supplied by each
partner. The Sinopec joint venture is expected to start development of sites in
2003. In addition, BP has 112 stations in Venezuela and 29 retail stations in
Mexico.
In March 2002, BP completed the sale of its 21 service stations in Japan to
Japan Energy. BP's exit from retail marketing in Japan is not expected to have
any impact on its other business activities there. In December 2002, BP sold its
49% stake in BP Oman SAOG to the state-owned Oman Oil Co. Ltd. This resulted in
the disposal of 74 retail service stations and some aviation and other business
to business activities. BP will continue to have a strong presence in Oman
through its downstream aviation, lubricants and marine businesses and other
activities. In Malaysia, BP sold 16 service stations and a small business to
business activity to Petronas; the transaction was completed in December 2002.
Lubricants
We manufacture and market lubricant products and also supply related
products and services to business customers and end-consumers in over 60
countries directly, and to the rest of the world through local distributors. Our
business is concentrated on the higher margin sectors of automotive lubricants,
especially in the consumer sector, but also has a strong presence in business
markets such as commercial vehicle fleets, marine and specialized industrial
segments.
We aim to achieve growth by further focusing our resources and capabilities
on selected market spaces. Relentless customer focus, distinctive brands and
superior technology remain the cornerstone of our long-term strategy.
Page 50
BP markets through its two major brands, Castrol and BP, and several
secondary brands including Duckhams and Veedol. The Veba acquisition
strengthened our lubricants position in Germany and in Central Europe with the
addition of the Aral brand to the BP Lubricants portfolio.
Our lubricants business is organized around the automotive segment as
follows:
Consumer markets: We supply lubricants, other products and related business
services to intermediate customers (for example retailers, workshops) who in
turn serve end-consumers (car, motorcycle, leisure craft owners) in the mature
markets of Western Europe and North America and also in the fast growing markets
of the developing world (e.g. Russia, China, India, Middle East, South America
and Africa). The Castrol brand is recognized worldwide and we believe it
provides us with a significant competitive advantage.
Commercial vehicle and general industrial markets: We supply lubricants and
lubricant-related services to the transportation industry and to automotive
manufacturers.
Business to Business Marketing
Our Business to Business Marketing encompasses marketing a comprehensive
range of products to other businesses. This business aims to build relationships
with customers that not only purchase a wide variety of products in large
quantities but also additional services. Logistics plays a crucial role in this
business. We aim to attract more customers through innovation in multi-product
offers and cleaner fuels, packaged with a range of value-added services and
solutions.
Our aviation business sells fuels and lubricants to airlines and general
aviation customers as well as providing technical services to airlines and
airports. During the last few years, our aviation business has strengthened its
position in established markets and pursued opportunities in new or emerging
markets. The business now markets in approximately 95 countries and is the third
largest jet fuel supplier globally.
Our LPG businesses sell bulk, bottled, automotive and wholesale products to
a wide range of customers in over 20 countries. During the past few years, our
LPG business has strengthened its position in established markets, pursued
opportunities in new and emerging markets and rationalized its operations.
During 2002, we successfully commissioned China's largest underground Cavern
complex for the storage of LPG.
In our marine business we supply lubricants and fuels, on a global basis,
to major shipping companies as well as to small fishing vessel operators. We are
the leading global participant in the marine lubricants market and operate a
network of offices and supply points in more than 900 ports across 90 countries.
In our specialized industrial segment we supply metalworking fluids and
lubricants alongside a range of business services, such as fluid management, to
the metal component manufacturing sector. We also have a significant high
performance industrial lubricants business in some key markets.
Supply and 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 function undertakes trading in physical and paper markets in order
to contribute to the Group's income.
Refer to Item 11 -- Quantitative and Qualitative Disclosures About Market
Risk for further information.
Page 51
Transportation
Our Refining and Marketing business owns, operates or has an interest in
extensive transportation facilities for crude oil, refined products and
petrochemical feedstock in the USA. 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 from our import terminals. We have interests in seven major crude oil
pipelines in the UK and the Rest of Europe and fifteen in the USA.
Bulk products are transported between refineries and storage terminals by
pipeline, ship, barge, and rail. Onward delivery to customers is primarily by
road. We have interests in nine major product pipelines in the UK and the Rest
of Europe and five in the USA.
BP sold its 17.97% interest in the Colonial Pipeline to Koch Industries in
November 2002, and took over operatorship of the Chicap Crude pipeline in
September 2002. The Company still maintains its share of 29.2% in the Chicap.
Shipping
BP Shipping owns or operates an international fleet of crude oil and
product tankers and LNG carriers transporting cargoes for the Group and for
third parties. It also offers a wide range of marine-related services to Group
and third party customers.
Excluding BP companies in the USA, at December 31, 2002 the Group
controlled or operated an international fleet of 17 oil tankers and 6 LNG ships
with total capacity of approximately 2.7 million deadweight tonnes (dwt). The
Group had four very large crude carriers, five medium sized crude carriers,
seven product carriers, and one North Sea shuttle tanker. It also operated one
LNG carrier to trade globally, four LNG carriers for Abu Dhabi contracted gas,
and one LNG carrier for the Western Australia North West Shelf (NWS) project. BP
holds an interest in six NWS gas carriers of which this is one.
BP Companies in the USA had seven large crude carriers, four medium crude
carriers, and six product carriers totalling approximately 1.54 million dwt on
long-term charter. BP owns four barges totalling 0.01 million dwt.
BP is in the middle of a new building programme which saw four ships
delivered into service in 2002.
In addition Group companies around the world charter a large number of
vessels.
Page 52
CHEMICALS
Our petrochemicals business is a major producer of chemicals through
subsidiaries, joint ventures and associated undertakings. BP has operations
principally in the USA and Europe. We are increasing our activities in the
Asia-Pacific region. The petrochemicals segment is also responsible for the
supply, marketing and distribution of chemical products to bulk, wholesale and
retail customers.
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Turnover (a)........................................................... 13,064 11,515 11,247
Total replacement cost operating profit ............................... 515 128 760
Total assets........................................................... 16,595 15,098 13,674
Capital expenditure and acquisitions................................... 823 1,926 1,585
($/tonne)
Chemicals Indicator Margin (b)......................................... 102(c) 109 126
----------
(a) Excludes BP's share of joint venture turnover of $511 million in 2002, $102
million in 2001, and $67 million in 2000.
(b) The Chemicals Indicator Margin (CIM) is a weighted average of externally
based product margins. It is based on market data collected by Nexant
(formerly Chem Systems) in their quarterly market analyses, then weighted
based on BP's product portfolio. While it does not cover our entire
portfolio, it includes a broad range of products. Among the products and
businesses covered in the CIM are the olefins and derivatives, the
aromatics and derivatives, linear alpha-olefins (LAOs), acetic acid, vinyl
acetate monomers and nitriles. Not included are fabrics and fibres, plastic
fabrications, poly alpha-olefins (PAOs), anhydrides, engineering polymers
and carbon fibres, speciality intermediates, and the remaining parts of the
solvents and acetyls businesses.
(c) Provisional. The data for the current year is based on eleven months of
actual data and one month of provisional data.
2002 was the first full year of operations following the acquisition of the
50% of Erdoelchemie we did not already own, and the Solvay transaction, which
resulted in the transfer of Solvay's US and European polypropylene businesses to
BP, the transfer of BP's engineering polymers buisness to Solvay, and the
combination of the two companies' European and US high-density polyethylene
businesses. Erdoelchemie has been renamed BP Koeln. In 2002, we acquired the
chemicals interests of Veba. We also continued to high grade our portfolio,
expand our existing capacity by debottlenecking or with new plant additions and
reduce our cost base. Since 2001, these efforts have grown capacity by 7% and
increased our efficiency by reducing cash fixed costs per tonne of capacity by
6%.
BP is now the world's third largest petrochemicals company in terms of
capacity, and manufactures and markets more than 26 million tonnes of products
each year.
Page 53
The following table shows BP production capacity (kilotonnes per annum
(ktepa)) by product and by region at December 31, 2002.
Rest of Rest of
Capacity by Region (a) UK Europe USA World Total
------- ------- ------- ------- -------
PTA...................................... -- 1,180 2,481 2,246 5,907
PX....................................... -- 583 2,320 -- 2,903
Ethylene and related co-products......... 1,575 4,247 2,267 64 8,153
Polypropylene............................ 270 1,052 1,276 -- 2,598
HDPE..................................... 165 617 412 530 1,724
Acrylonitrile/Acetonitrile............... -- 300 677 -- 977
Acetic acid.............................. 781 -- 491 875 2,147
Other.................................... 1,843 5,365 2,154 342 9,704
------ ------ ------ ------ ------
Total 4,634 13,344 12,078 4,057 34,113
====== ====== ====== ====== ======
------------
(a) Includes BP share of joint ventures, associated undertakings and other
interests in production.
Approximately 2,100 ktepa of our production capacity increase from 2001
resulted from our acquisition of Veba.
During the year, we completely reviewed our strategy and are now focusing
on seven core products. The outcome of the review is to pursue a strategy aimed
at providing industry-leading performance in all aspects of our activities. The
mechanisms for achieving this objective are:
Differentiation -- creating a material and differentiated portfolio, which,
by matching our products and services with customer needs, and through selective
integration, creates distinctive performance in our chosen areas of various
value chains.
Focus -- growing seven core products where our emphasis is on developing
and retaining advantaged positions. In addition we have a number of closely
associated products.
Capability -- further developing our functional capabilities in innovative
proprietary technology, world-class manufacturing, market excellence and
commercial optimization.
The seven core products within our portfolio are:
Purified Terephthalic Acid (PTA)
PTA is important as a raw material for the manufacture of polyester used in
textiles, fibres and films. BP is the world's largest producer of PTA, with an
interest in approximately 20% 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 Samsung
Petrochemical Company (SPC) in Korea (BP 35%), China American Petrochemical
Company (CAPCO) in Taiwan (BP 50%), PT Ami in Indonesia (BP 50%) and Rhodiaco in
Brazil (BP 49%). The sites in Taiwan, Korea, Belgium and the USA are among the
largest PTA production sites in the world.
Major Activities
-- During 2001, construction began on a new PTA plant in Taiwan. The
plant, to be operated by our CAPCO joint venture, will add 700 ktepa
capacity and is expected to commence operation during 2003.
-- Construction on the Zhuhai (BP 85%) plant was completed in early 2003
and operation has commenced. This plant will add 350 ktepa capacity.
Page 54
-- BP further refined its options for the site of the next European PTA
investment. This is intended to be a world-scale development located
in Northwestern Europe which will take into account integration with
customers and feedstock.
-- BP, in collaboration with several industry partners, has developed a
polyethylene terephthalate (PET) beer bottle. We believe this to be
technically best in class and cost competitive with glass. Market
evaluation and roll out occurred during 2002. The aim is to establish
PET as a competitive third packaging material in the global beer
market, potentially developing new markets for BP's polyester
intermediate product lines.
Paraxylene (PX)
PX is feedstock for the production of PTA and is manufactured from mixed
xylene streams acquired from BP refineries and third party producers. We are
currently the global leader in PX. Our plants are located in Decatur, Alabama
and Texas City, Texas in the USA and Geel in Belgium. Joint efforts with
Refining and Marketing continue to maximize sourcing of xylenes feedstock from
BP refineries.
Ethylene (and related co-products)
We produce and market the basic petrochemical building blocks, known as
olefins, that are used primarily as raw material for other chemical products.
These olefins are derived from the steam cracking of liquid and gaseous
hydrocarbons.
The olefins -- ethylene, propylene and butadiene -- are produced by
crackers at Grangemouth, UK; Lavera, France (Naphtachimie - BP 50%); Koeln,
Germany and Chocolate Bayou, Texas in the USA. Olefins are also manufactured by
Ethylene Malaysia Sdn. Bhd. (BP 15%) at Kertih, Malaysia. The Veba share of
production in the crackers at Gelsenkirchen and Munchmunster in Germany was
added during 2002 through acquisition. Crackers produce the raw materials for
the production of derivative products including polyethylene, polypropylene,
acrylonitrile, styrene, ethanol and ethylene oxide, which are also produced at
various BP plants.
Major Activities
-- In February 2002 and June 2002, BP acquired first a majority stake and
then complete ownership of Veba, based in Germany. Veba's
petrochemicals business, based at Gelsenkirchen and Munchmunster in
Germany, with Veba's share of ethylene capacity of 810 ktepa, will
help meet BP's future chemical feedstock needs in the region.
-- BP successfully completed and commissioned a 200-ktepa cracker
expansion at Koeln.
-- In December 2001 BP, Sinopec and Shanghai Petrochemicals Company
announced the formation of SECCO (BP 50%), which plans to build a
$2.7-billion petrochemicals complex near Shanghai. The integrated
complex will be centred around a 900-ktepa naphtha cracker producing
a range of olefins and related derivatives. In January 2002 we
announced a loan facility in the amount of $1.8 billion with nine UK
and two international banks to provide financing for the project.
Construction began in late 2002, and the first contracts were awarded
in 2003. Operation is expected to begin in 2005.
-- In the USA, we announced our intention to increase ethylene capacity
at Chocolate Bayou, Texas by 295 ktepa.
Page 55
Polypropylene
Polypropylene is used for moulded products, fibres and films. We are the
second largest producer of polypropylene in the world, with manufacturing
facilities at Chocolate Bayou and Deer Park, Texas and Carson City, California
in the USA; Lillo and Geel, Belgium and Sarralbe, France.
Major Activities
-- In 2002 we elected to rationalize our polypropylene activities in the
USA, closing the Cedar Bayou operation and shutting a unit at
Chocolate Bayou.
-- Late in 2002 we increased our interest in the Carson, California
polypropylene unit from 85% to 100%.
-- The complex near Shanghai, planned by SECCO (BP 50%), is expected to
add 250 ktepa of polypropylene when completed in 2005.
High Density Polyethylene (HDPE)
Polyethylene is used for packaging, pipes and containers. BP Solvay
Polyethylene Europe (BP 50%) has HDPE plants at Grangemouth, UK; Lillo, Belgium;
Sarralbe and Lavera, France; and Rosignano, Italy. In addition BP Solvay
Polyethylene North America (BP 49%) has a HDPE plant at Deer Park, Texas. We
also produce HDPE through Polyethylene Malaysia Sdn. Bhd. (BP 60%) at Kertih,
Malaysia.
Major Activities
-- We announced the intended closure of our smaller 118-ktepa HDPE plant
at Deer Park, Texas in light of the opening of a new more efficient
600-ktepa, world scale HDPE plant (BP 25%) in Houston, Texas.
-- In light of continuing difficult market conditions in Asia we decided
to exit the mothballed Bataan Polyethylene Company plant (BP 39%) in
the Philippines, and commence the sale of our share in PT Peni (BP
75%) at Merak, Indonesia.
-- The complex near Shanghai, planned by SECCO (BP 50%), is expected to
add 600 ktepa of HDPE/linear-low density polyethylene (LLDPE) when
completed in 2005.
Acrylonitrile
BP is the world's largest producer and marketer of acrylonitrile, which is
used in textiles and plastics for the automobile and consumer goods industries.
We operate two acrylonitrile plants at Green Lake, Texas and Lima, Ohio in the
USA. Green Lake, with a capacity of 450 ktepa, is the largest acrylonitrile
production site in the world. Acrylonitrile is also produced at Koeln, Germany
and through a capacity rights agreement with Sterling Chemicals at Texas City,
Texas in the USA. Additionally, BP is the world's largest producer and marketer
of the co-product, acetonitrile, primarily sold for pharmaceutical applications.
Major Activities
-- The planned SECCO complex near Shanghai (BP 50%) is intended to
produce 260 ktepa of acrylonitrile when complete in 2005.
Page 56
Acetic Acid
We are a major manufacturer and supplier of acetic acid, a versatile
chemical used in a variety of products such as foodstuffs, textiles, paints,
dyes and pharmaceuticals. Acetic acid is also used in the production of PTA. BP
has acetic acid operations in Europe, the USA, in Korea through Samsung - BP
Chemicals (BP 51%), in China through Yangtze River Acetyls Company (BP 51%) and
in Malaysia through BP Petronas Acetyls Sdn. Bhd. (BP 70%).
Major Activities
-- We established a new joint venture with Formosa Chemicals and Fibre
Corporation (BP 50%), with a view to building a 300-ktepa acetic acid
plant in Taiwan around 2005.
Other Products
In addition to the seven core products, we are involved in a number of
other closely related products. These include LLDPE and low density polyethylene
(LDPE), used in a wide range of applications including packaging, as is styrene,
ethylene oxide and ethanol,all used in solvents, coatings, and the automotive
industry, LAOs, used as a plasticiser; PAOs, used in both synthetic lubricants
and surfactants, purified isophthalic acid (PIA), used for isopolyester resins
and gel coats; napthalene dicarboxylate (NDC), used for photographic film and
specialized packaging; polybutene, used in lubricants and fuel additives;
trimellitic anhydride (TMA), used by the automotive and consumer goods
industries; butanediol (BDO), used in synthetic materials and engineering
plastics; maleic anhydride (MAN), used in a wide range of plastics and resins;
ethyl acetate, and vinyl acetate monomer (VAM), used in coatings and textile
applications.
BP operates LLDPE plants at Grangemouth in the UK and Koeln in Germany.
Koeln also produces LDPE.
We operate styrene monomer plants at Texas City, Texas in the USA and Marl
in Germany. Polystyrene plants are operated at Marl in Germany, Wingles in
France and Trelleborg in Sweden. Expanded polystyrene plants are operated at
Wingles and Marl.
PIA is produced at Joliet, Illinois in the USA; Geel, Belgium; and by the
AG International Chemicals Company joint venture (BP 50%) with Mitsubishi Gas
Chemical Company in Japan. NDC is produced at our plant in Decatur, Alabama in
the USA.
BP manufactures polybutene at Whiting, Indiana in the USA and at Lavera,
France. A plant at Texas City, Texas ceased production in 2002.
LAOs are produced at our facilities in Pasadena, Texas in the USA; Joffre,
Canada and Feluy, Belgium. We manufacture PAOs at our facilities in Deer Park,
Texas in the USA and Feluy, Belgium.
We produce TMA and MAN at Joliet, Illinois in the USA. We manufacture BDO
using our proprietary technology in a world-scale plant at Lima, Ohio in the
USA.
In Korea, the Asian Acetyls Company (BP 34%) operates a 150-ktepa plant
producing VAM, a derivative of acetic acid. A new 250-ktepa VAM plant at Hull
was commissioned during 2001 and the VAM plant at Baglan Bay in Wales closed
during 2002.
Major Activities
-- The 110-ktepa ethanol plant at Grangemouth was commissioned as
planned.
-- We announced the cessation of the production of alcohols on our site
at Pasadena, Texas. The 60-ktepa plant stopped during the fourth
quarter 2002 when this site began concentrating on the production of
LAOs.
Page 57
-- The proposed 65-ktepa TMA plant at our existing PTA complex in
Kuantan, Malaysia had advanced to construction bid stage. As a
consequence of current market conditions, this TMA plant construction
has been cancelled.
-- In Korea we exited the acetate esters business, International Esters
Co. (BP 50%).
We have implemented or announced a number of structural changes that we
believe should significantly strengthen our position as the petrochemicals arm
of an integrated energy company. The most significant structural changes were as
follows:
-- During 2002, we sold our Plastics Fabrications Group.
-- During 2002, we wrote down the value of our manufacturing assets in
the Philippines and Indonesia, thus reflecting the difficult market
conditions expected to prevail in the region.
-- During 2002, we sold Fosroc Construction, and in early 2003 announced
the sale of the two remaining Burmah Castrol Chemicals businesses
(Fosroc Mining and Sericol).
-- Early in 2003 we announced our intention to sell our wholly-owned TMA,
PIA and MAN business in Joliet, Illinois in the USA and PIA produced
at our integrated aromatics and polyolefins complex in Geel, Belgium.
Manufacturing Facilities
BP has large-scale manufacturing facilities in Europe and the USA. The
Group's major sites, with our share of their capacities are: Grangemouth (2,930
ktepa) and Hull (1,595 ktepa) in the UK; Lavera (1,800 ktepa) in France; Marl
(630 ktepa), Gelsenkirchen (1,700 ktepa) and Koeln (4,730 ktepa) in Germany;
Geel (2,300 ktepa) in Belgium; and Texas City, Texas (2,690 ktepa), Chocolate
Bayou, Texas (2,650 ktepa), Decatur, Alabama (2,280 ktepa), and Cooper River,
South Carolina (1,330 ktepa) in the USA.
We also aim to grow in the Asia-Pacific region, which offers prospects for
demand growth. The intention is to build further on the positions that the Group
now holds in the region through planned investment and commercial relationships,
such as joint ventures. Our share of capacity in Asia amounts to 3,670 ktepa, as
follows: Indonesia (580 ktepa), Korea (820 ktepa), Malaysia (1,440 ktepa),
Taiwan (680 ktepa), China (105 ktepa), and Japan (45 ktepa).
Years ended December 31,
--------------------------------
Production by region (a) 2002 2001 2000
-------- -------- ---------
(kte)
UK..................................................................... 3,221 3,126 3,137
Rest of Europe......................................................... 10,526 7,925 6,713
USA.................................................................... 10,201 8,943 9,874
Rest of World.......................................................... 3,040 2,722 2,341
------ ------ ------
Total Production (a)................................................... 26,988 22,716 22,065
====== ====== ======
----------
(a) Includes BP share of joint ventures, associated undertakings and other
interests in production.
BP's petrochemical products are sold to companies in a number of industries
that manufacture components used in a wide range of applications. These include
the agriculture, automotive, construction, furniture, household products,
insulation, packaging, paint, pharmaceuticals and textile industries. Our
products are marketed through a network of sales personnel and agents who also
provide technical services.
Page 58
OTHER BUSINESSES AND CORPORATE
Other Businesses and Corporate comprises Finance, the Group's coal asset
and aluminium asset, its investments in PetroChina and Sinopec, interest income
and costs relating to corporate activities worldwide.
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Turnover............................................................... 510 549 59
Total replacement cost operating loss.................................. (701) (523) (1,071)
Total assets........................................................... 6,987 7,527 11,498
Capital expenditure and acquisitions (a)............................... 428 430 30,576
----------
(a) Capital expenditure and acquisitions in 2000 includes $27,506 million for
the acquisition of ARCO and $994 million for the acquisition of interests
in PetroChina and Sinopec.
On January 1, 2002 the solar, renewables and alternative fuels activities
were transferred to Gas, Power and Renewables. Comparative information has been
restated.
Finance coordinates the management of the Group's major financial assets
and liabilities. From locations in the UK, Europe, the USA and the Asia-Pacific
region, it provides the link between BP and the international financial markets,
and makes available a range of financial services to the Group including
supporting the financing of BP's projects around the world.
Coal activity consists of our 50% interest in PT Kaltim Prima Coal, an
Indonesian company. This company operates an opencast coal mine at Sangatta in
Kalimantan, Indonesia.
Aluminium. Our aluminium business is a non-integrated producer and marketer
of rolled aluminium products, headquartered in Louisville, Kentucky, USA.
Production facilities are located in Logan County, Kentucky and are jointly
owned with Alcan Aluminum. The primary activity of our aluminium business is the
supply of aluminium coil to the beverage can business.
Investments in China. During 2000 BP made two strategic investments in
China, one of the world's fastest growing economies. BP invested $416 million in
the China Petroleum and Chemical Corporation (Sinopec) and $578 million in
PetroChina in the initial public offerings of both companies. BP has an interest
of around 2% in each company. Separately, BP has formed a joint venture with
PetroChina in Guangdong province which had 320 service stations at the end of
2002, and has agreed to form a joint venture with Sinopec to acquire, revamp or
build service stations in the Zhehang Province. PetroChina and Sinopec are two
of China's major companies in the oil and chemicals businesses.
Research, technology and engineering activities are carried out by each of
the major business segments on the basis of a distributed programme coordinated
by the BP Technology Council. This body provides leadership for scientific,
technical and engineering activities throughout the Group and in particular
promotes cross-business initiatives and the transfer of best practice between
businesses. In addition, a group of eminent industrialists and academics form
the Technology Advisory Council, which advises senior management on the state of
technology within the Group and helps identify current trends and future
developments in technology.
Research and development is carried out using a balance of internal and
external resources. Involving third parties in the various steps of technology
development and application enables a wider range of technology solutions to be
considered and implemented, improving the productivity of research and
development activities.
Page 59
The innovative application of technology and the rapid transfer of this
knowledge through the Group make a key contribution to improving BP's business
performance, particularly in the areas of the introduction of new products,
safety, the environment, cost reduction and efficiency of business operations.
We believe that, in addition to improving existing business performance, the use
of innovative technology can create new possibilities for the organic growth of
our energy- and petrochemical-related businesses.
Insurance. The Group generally restricts its purchase of insurance to
situations where this is required for legal or contractual reasons. This is
because external insurance is not considered an economic means of financing
losses for the Group. Losses will therefore be borne as they arise, rather than
being spread over time through insurance premia with attendant transaction
costs. The position is reviewed from time to time.
Page 60
REGULATION OF THE GROUP'S BUSINESS
United Kingdom
BP's exploration and production activities are conducted in many different
countries and are therefore subject to a broad range of legislation and
regulations. These cover virtually all aspects of exploration and production
activities, including matters such as license acquisition, production rates,
royalties, pricing, environmental protection, export, taxes and foreign
exchange. The terms and conditions of the leases, licenses and contracts under
which these oil and gas interests are held vary from country to country. These
leases, licenses and contracts are generally granted by or entered into with a
government entity or state company and are sometimes entered into with private
property owners. These arrangements usually take the form of licenses or
production sharing agreements.
Licenses (or concessions) give the holder the right to explore for and
exploit a commercial discovery. Under a license, the holder bears the risk of
exploration, development and production activities and provides the financing
for these operations. In principle, the license holder is entitled to all
production minus any royalties that are payable in kind. A license holder is
generally required to pay production taxes or royalties, which may be in cash or
in kind.
Production sharing agreements entered into with a government entity or
state company generally obligate BP to provide all the financing and bear the
risk of exploration and production activities in exchange for a share of the
production remaining after royalties, if any.
In certain countries, separate licenses are required for exploration and
production activities and, in certain cases, production licenses are limited to
a portion of the area covered by the exploration license. Both exploration and
production licenses are generally for a specified period of time (except for
production licenses in the United States which remain in effect until production
ceases). The term of BP's licenses and the extent to which these licenses may be
renewed vary by area.
In general, BP is required to pay income tax on income generated from
production activities (whether under a license or production sharing agreement).
In addition, depending on the area, BP's production activities may be subject to
a range of other taxes, levies and assessments, including special petroleum
taxes and revenue taxes. The taxes imposed upon oil and gas production profits
and activities may be substantially higher than those imposed on other
businesses.
BP's other activities are also subject to a broad range of legislation and
regulations in various countries in which it operates.
Health, safety, and environmental regulations are discussed in more detail
in this item under 'Environmental Protection'.
Page 61
ENVIRONMENTAL PROTECTION
Health, Safety and Environmental Regulation
The Group is subject to numerous national and local environmental laws and
regulations concerning its products, operations and activities. Current and
proposed fuel and product specifications under a number of environmental laws
will have a significant effect on the production, sale and profitability of many
of our products. Environmental laws and regulations also require the Group to
remediate or otherwise redress the effects on the environment of prior disposal
or release of chemicals or petroleum substances by the Group or other parties.
Such contingencies may exist for various sites including refineries, chemicals
plants, natural gas processing plants, oil and natural gas 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 often inherently difficult to estimate. They depend on
the magnitude of any possible contamination, the timing and extent of the
corrective actions required and BP's share of liability relative to that of
other solvent responsible parties. Though the costs of future restoration and
remediation could be significant, and may be material to the results of
operations in the period in which they are recognized, it is not expected that
such costs will have a material impact on the Group's overall financial position
or liquidity.
The Group's operations are also subject to environmental and common law
claims for personal injury and property damage caused by the release of
chemicals, hazardous materials or petroleum substances by the Group or others.
Proceedings instituted by governmental authorities are pending or known to be
contemplated against BP and certain of its US subsidiaries under US federal,
state or local environmental laws, each of which could result in monetary
sanctions in excess of $100,000. No individual proceeding is, nor are the
proceedings as a group, expected to have a material adverse effect on BP's
consolidated financial position or profitability.
Management cannot predict future developments, such as increasingly strict
requirements of environmental laws and enforcement policies thereunder, that
might affect the Group's operations or affect the exploration for new reserves
or the products sold by the Group. A risk of increased environmental costs and
impacts is inherent in particular operations and products of the Group and there
can be no assurance that material liabilities and costs will not be incurred in
the future. In general, the Group does not expect that it will be affected
differently from other companies with comparable assets engaged in similar
businesses. Management believes that the Group's activities are in compliance in
all material respects with applicable environmental laws and regulations.
For a discussion of the Group's environmental expenditures see Item 5 --
Operating and Financial Review and Prospects -- Environmental Expenditure.
BP operates in over 100 countries worldwide. In all regions of the world BP
has processes to ensure compliance with applicable regulations. In addition,
each individual in the Company is required to comply with the BP Health Safety
and Environment policy, and associated expectations and standards. Our partners,
suppliers and contractors are also encouraged to adopt them. This document
focuses primarily on the US and EU where over 80% of our fixed assets are
located - and on two issues of a global nature; climate change programmes; and
maritime oil spills regulations.
Page 62
Climate Change Programs
Kyoto Protocol
In December 1997, at the Third Conference of the Parties to the United
Nations Framework Convention on Climate Change (UNFCCC) in Kyoto, Japan, the
participants agreed on a system of differentiated internationally legally
binding targets for the first commitment period of 2008 to 2012. Before it can
be implemented, the Kyoto protocol to the UNFCCC needs to be ratified by at
least 55 nations, representing a minimum of 55% of global anthropogenic
greenhouse gas (GHG) emissions. The US has indicated that it will not ratify.
Therefore, in order for the treaty to come into force, both Russia and Canada
need to ratify, in addition to those nations which have either already ratified
or indicated that they will ratify. If the Kyoto treaty does enter into force
and its targets are to be met, some reduction in the use of fossil fuels would
be required within countries which have ratified the Kyoto treaty. The impact of
the Kyoto agreements on global energy (and fossil fuel) demand is expected to be
small (see International Energy Agency Global Energy Outlook, 2000 Edition).
Since 1997, BP has been actively involved in policy debate, worked with
others on mitigating technologies, demonstrated global emissions trading and
reduced the emissions from our facilities. Last year, we announced that we had
succeeded in reducing our direct, equity share, GHG emissions by 10%, and set a
target to maintain our net emissions at 2001 levels through the next decade,
which is dependent upon the resolution of the various international policy
discussions on market mechanisms.
BP is an advocate of market mechanisms to allow optimum utilization of
resources to meet national Kyoto targets. Such systems are being considered,
developed or implemented by individual countries, and also internationally
through the European Union. The relative success of these systems will determine
the extent to which alternative fiscal or regulatory measures may be applied.
Some EU member States have indicated that they require energy product taxes to
enable them to meet their Kyoto commitments within the EU burden sharing
agreement, and are already implementing national legislation, such as the UK
Climate Change Levy.
United Kingdom Emissions Trading Scheme
In April 2002, we joined the UK government-sponsored emissions trading
scheme, the world's first scheme to cross industry sectors. We successfully made
a 353,500 tonnes of carbon dioxide equivalent emissions reduction commitment
into the UK Scheme equating to nearly 10% of the total commitment made by UK
industry entering into the Scheme as `Direct Participants' via the auction. If
BP does not meet the targets, a proportion of the incentive money would be at
risk and rules could be imposed during 2003 which may penalize companies in
future for exceeding the agreed targets. This market is at its early stages and
the risk of significant penalties from BP participation in the scheme is small.
European Union Emissions Trading Scheme
In December 2002, EU Member States' Environment Ministers reached political
agreement on the proposal for a Directive of the European Parliament and the
Council establishing a scheme for greenhouse gas emission allowance trading
within the Community (this proposal amends Directive 96/61/EC). The political
agreement will have its second reading later in 2003. It aims to create an
instrument to reduce emissions of GHGs in a cost-effective manner, in order to
allow the Union to meet its obligations under the UNFCCC and the Kyoto Protocol.
It may proceed even without ratification of the Kyoto Protocol at the
international level. Once ratified in member states, the programme would be
mandatory for all enterprises producing emissions from combustion installations
greater than 20 MW rated thermal input. It would apply to BP's European
refineries, chemical sites with crackers, upstream offshore installations and
possibly flares.
Page 63
Maritime Oil Spill Regulations
Within the United States, the Oil Pollution Act of 1990 significantly
increased oil spill prevention requirements. Details of this legislation are
provided in the regional review below. Outside of the United States, the BP
operated fleet of tankers is subject to international spill response and
preparedness regulations that are typically promulgated through the
International Maritime Organization (IMO) and implemented by the relevant flag
state authorities. The International Convention for the Prevention of Pollution
From Ships (Marpol 73/78) requires vessels to have detailed shipboard emergency
and spill prevention plans. The International Convention on Oil Pollution,
Preparedness, Response, and Co-Operation (OPRC) requires vessels to have
adequate spill response plans, resources, and financial cover for response
anywhere the vessel travels to. These conventions and separate Marine
Environmental Protection Circulars also stipulate the relevant state authorities
around the globe that require engagement in the event of a spill. All of these
requirements together are addressed by the vessel owners in Shipboard Oil
Pollution Emergency Plans.
Since 1995, BP Shipping has taken 10 single hull vessels out of service. At
the end of 2002 our international fleet numbered 17 oil tankers with an average
age of six years (13 are double-hulled, three are double-sided, one is a
single-hulled ear-marked for disposal) and six gas ships with an average age of
eight years. The fleet renewal programme will continue into the future and
should see 16 modern double-hulled vessels delivered by the end of 2003, with a
further 19 confirmed for 2004 onwards. In addition to its own fleet, BP will
continue to charter quality ships; currently these vessels include both single-
and double-hulled designs but all are vetted to BP's high standard prior to each
use to ensure they are operated and maintained to meet our stringent
requirements.
United States Regional Review
The following is a summary of significant US environmental legislation
affecting the Group.
The Clean Air Act and its regulations require, among other things, new fuel
specifications and sulphur reductions, enhanced monitoring of major sources of
specified pollutants; stringent air emission limits and new operating permits
for chemical plants, refineries, marine and distribution terminals; and risk
management plans for storage of hazardous substances. This law affects BP
facilities producing, refining, manufacturing and distributing oil and products
as well as the fuels themselves. Federal and state controls on ozone, carbon
monoxide, benzene, sulphur, MTBE, nitrogen dioxide, oxygenates and Reid Vapor
Pressure impact BP's activities and products in the US. BP is continually
adapting its business to these rules and has the know-how to produce quality and
competitive products in compliance with their requirements. For example, in
1999, BP introduced a premium grade gasoline in Atlanta, Georgia, meeting
stringent future sulphur standards and has expanded this offering to over 40
cities across the US.
In 2001, BP entered into a consent decree with the EPA and several states
that settled alleged violations of various Clean Air Act requirements related
largely to emissions of sulphur dioxide and nitrogen dioxide at BP's refineries.
This settlement requires the installation of additional controls at all of BP's
US refineries at a cost, over at least an eight-year period, of approximately
$500 million, and the one-time payment of a $10 million penalty which was made
in 2001.
On March 11, 2003 the South Coast Air Quality Management District filed a
complaint against BP West Coast Products LLC and Atlantic Richfield Company in
Los Angeles County Superior Court, alleging multiple violations of air quality
regulations at the Carson oil refinery in California, USA. Atlantic Richfield
Company operated the refinery until its acquisition by the Group in 2000. The
complaint seeks penalties for non-compliance in the amount of $319 million. BP
believes that it has valid defenses to many of the allegations of the complaint,
believes that the amount of the penalty sought is grossly disproportionate to
any resulting environmental harm, and intends to defend the action vigorously.
Page 64
BP is in the fourth year of implementing a plea agreement with the US
Justice Department to develop, implement and maintain a nationwide environmental
management system (EMS) consistent with the best environmental practices at
Group facilities engaged in oil exploration, drilling and/or production in the
US and its territories. BP expects to have EMSs fully implemented for Alaska and
Lower 48 performance units during 2003. BP has met the requirement to spend at
least $15 million on the programme.
The Clean Water Act is designed to protect and enhance the quality of US
surface waters by regulating the discharge of wastewater and other pollutants
from both onshore and offshore operations. Facilities are required to obtain
permits for most surface water discharges, install control equipment and
implement operational controls and preventative measures, including spill
prevention and control plans. Requirements under the Clean Water Act have become
more stringent in recent years, including coverage of storm and surface water
discharges at many more facilities and increased control of toxic discharges.
BP was fined approximately $25 million for underground storage tank
allegations in its US Retail operations. These fines constituted 90% of the
total fines and penalties paid by BP in 2002. In addition to these fines, BP
paid $3 million for supplemental environmental projects; approximately $24
million in miscellaneous environmental funds and projects and $6 million in
associated legal costs.
The Oil Pollution Act of 1990 or OPA 90 significantly increased oil spill
prevention requirements, spill response planning obligations and spill liability
for tankers and barges transporting oil, offshore facilities such as platforms
and onshore terminals. To provide funds for response to and compensation for oil
spills when the spiller is unable to do so, the Oil Pollution Act created a
$1-billion fund which is funded by a tax on imported and domestic oil. One
requirement of the Oil Pollution Act is that all new tank vessels operating in
US waters must have double hulls, and the law orders the phase out, between the
years 1995 and 2015, of existing vessels without double hulls. In 2002, BP began
construction of four double hull tankers at a shipyard in San Diego, California.
The first of these new vessels should begin service in early 2004. BP has
interest in the Alaska Tanker Company (ATC) in the US. Since 1995, seven ATC
single hull vessels have been taken out of service (replaced with chartered
tonnage). The current ATC fleet consists of six single hull vessels and three
double hull vessels. By the end of 2006 all ATC vessels are expected to be
double hulled vessels.
BP has a national strike team, the BP Americas Response Team, which
consists of approximately 240 trained emergency responders at company locations
throughout North America, which is ready to assist in a response to a major
incident.
The Resource Conservation and Recovery Act (RCRA) regulates the storage,
handling, treatment, transportation and disposal of hazardous and non-hazardous
wastes. It also requires the investigation and remediation of certain locations
at a facility where such wastes have been handled, released or disposed of. BP
facilities generate and handle a number of wastes regulated by RCRA and have
units that have been used for the storage, handling or disposal of RCRA wastes
that are subject to investigation and corrective action.
Under the Comprehensive Environmental Response, Compensation, and Liability
Act (also known as CERCLA or Superfund), waste generators, site owners, facility
operators and certain other parties are strictly liable for part or all of the
cost of addressing sites contaminated by spills or waste disposal regardless of
fault or the amount of waste sent to a site. Additionally, each state has laws
similar to CERCLA.
Page 65
BP has been identified as a Potentially Responsible Party (PRP) under
CERCLA and similar state statutes at approximately 800 sites. A PRP has joint
and several liability for site remediation costs under some of these statutes
and so BP may be required to assume, among other costs, the share attributed to
insolvent, unidentified or other parties. BP has the most significant exposure
for remediation costs at 75 of these sites. For the remaining sites, the number
of PRPs can range up to 200 or more. BP expects its share of remediation costs
at these sites to be small in comparison to the major sites. BP has estimated
its potential exposure at all sites where it has been identified as a PRP and
has accrued provisions accordingly. BP does not anticipate that its ultimate
exposure at these sites individually, or in the aggregate, will be significant
except as reported for ARCO in the matters below.
The State of Montana has pursued claims against ARCO alleging natural
resource damages arising out of ARCO's predecessors' mining and mineral
processing activities. In addition, a tribe was allowed to intervene in the
lawsuit, Montana vs. ARCO. These matters were settled in part in 1999, except
for the State's claims for $206 million for restoration damages at several
sites. In 1989, the EPA filed a CERCLA cost recovery action against Atlantic
Richfield Company for oversight costs at several of the Upper Clark Fork River
Basin Superfund sites US v. ARCO. Litigation is proceeding on both the EPA's
claim, and on ARCO's counterclaims against various federal agencies seeking
contribution from the federal agencies for remediation costs and for any natural
resource damage liability it might incur in Montana vs. ARCO. The settlements in
Montana vs. ARCO, and subsequent settlements resolved the claims and
counterclaims in US vs. ARCO pertaining to four sites and may provide a
framework for possible future settlement of the remaining claims. The Group is
also subject to other claims for natural resource damage (NRD) under several
federal and state laws. This is a developing area under US law which could
impact the cost of some cleanups. NRD claims have been asserted by government
trustees against several refineries and other company operations.
In 1995, a final federal rule was issued regarding protection of the Great
Lakes watershed which has had ongoing impacts on water protection requirements.
In 2000, a final federal rule was issued regarding use of Total Maximum Daily
Load (TMDL) assessments to address pollutants not meeting water quality
standards. EPA deferred implementation of the rule to April 2003 and in December
2002, proposed to withdraw the rule. However, the TMDL programme is going
forward under existing regulations with the effect of requiring more stringent
permit limits at affected industrial facilities. In May 2002, EPA published a
draft strategy for water quality standards and criteria. The strategy lays out
actions through 2008 addressing a broad range of issues with implications for
industrial facilities; these include water use designations, antidegradation,
TMDLs, mixing zones, water quality protection criteria, and contaminated
sediments.
In the US, many environmental cleanups are the result of strict groundwater
protection standards at both the state and federal level. Contamination or the
threat of contamination of current or potential drinking water resources can
result in stringent cleanup requirements, but some states have addressed
contamination of nonpotable water resources using similarly strict standards. BP
has encouraged risk-based approaches to these issues and aims to tailor remedies
at its facilities to match the level of risk presented by the contamination.
Other significant legislation includes the Toxic Substances Control Act
which regulates the development, testing, import, export and introduction of new
chemical products into commerce; the Occupational Safety and Health Act which
imposes workplace safety and health, training and process standards to reduce
the risks of chemical exposure and injury to employees; 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.
See also Item 8 -- Financial Information -- Legal Proceedings.
Page 66
European Union Regional Review
A European Commission (the Commission) Directive for a system of Integrated
Pollution Prevention and Control (IPPC) was approved in 1996. This system
requires permitting through the application of Best Available Techniques (BAT)
taking into account the costs and benefits. In the event that the use of BAT is
likely to result in the breach of an environmental quality standard, plant
emissions must be reduced further. The European Commission has stated that it
hopes that all processes to which it applies will be licensed by July 2005. All
plants must be permitted according to the requirements of the IPPC Directive by
November 2007. The Directive encompasses most activities and processes
undertaken by the oil and petrochemical industry within the European Union and
requires capital and revenue expenditure across these BP sites. The European
Commission is expected to make recommendations for a revision to the IPPC
Directive in 2003. This may tighten minimum standards for permitting including
the provision of emission limit values.
The European Union Large Combustion Plant Directive sets emission limit
values for sulphur dioxide, nitrogen oxides and particulates from large
combustion plants. It also required phased reductions in emissions from existing
large combustion plants at the latest by April 1, 2001. A revised Large
Combustion Plant Directive has been agreed and implementation is required by
November 27, 2002. Plants will have to comply by 2008. The second important set
of air emission regulations affecting BP European operations is the Air Quality
Framework Directive and its three daughter Directives on ambient air quality
assessment and management, which prescribe, among other things, limit values for
sulphur dioxide, oxides of nitrogen, particulate matter, lead, carbon monoxide,
benzene and ozone. Measured or modelled exceedences of air quality limit values
will require local action to reduce emissions and may impact any BP operations
whose emissions contribute to such exceedences.
BP continues to make investments on Cleaner Fuels at its refineries
worldwide. For our European refineries, these investments are important because
availability of cleaner fuels is a part of the EU strategy to combat air
pollution. 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 is limited to 0.2% from July 2000, and 0.1%
from January 2008. From January 2003, sulphur in heavy fuel oil is 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.
The EU has set stringent objectives to control exhaust emissions from
vehicles, which are being implemented in stages. 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. In 1999, this was followed by emission limits for heavy commercial
vehicles. Maximum sulphur levels for gasoline and diesel fuels to apply from
2005 have also been agreed at 50 parts per million (ppm), and 35% maximum
aromatic content for gasoline from the same date. Agreement was reached in
December 2002 on a further Directive to make petrol and diesel with a maximum
sulphur content of 10 ppm mandatory throughout the EU from January 2009, and
from 2005 member states will also have to supply low-sulphur fuel at enough
locations to allow the circulation of new low-emission engines requiring the
cleaner fuel.
In Europe there is no overall soil protection regulation, although a draft
Directive is expected in 2003. Certain individual member states have soil
protection policies, but each has its own contaminated land regulations. There
are common principles behind these regulations, including a risk based approach
and recognition of costs versus benefits. Much of the technical guidance
supporting these regulations is in draft form.
Other environment-related existing regulations include: the Major Hazards
Directive which requires emergency planning, public disclosure of emergency
plans and ensuring that hazards are assessed, and effective emergency management
systems; the Water Framework Directive which includes protection of groundwater;
and the Framework Directive on Waste to ensure that waste is recovered or
disposed without endangering human health and without using processes or methods
which could harm the environment.
Page 67
There are many other environmental regulations at national levels,
including those to implement existing EU Directives outlined above. Individually
these national regulations are less significant in their overall impact on BP.
The European Commission is expected soon to release a draft proposal
setting out the system for Registration, Evaluation and Authorisation of
Chemicals. It is anticipated that up to 100,000 chemicals, including
intermediaries and polymers, could be captured by the legislation. Additional
complexity and costs for the important small and medium enterprise (SME) sector
of the chemical industry could be severe, with adverse impact on employment,
innovation and competitiveness. Costs to BP will mainly arise from erosion of
the SME customer base.
The European Commission issued a proposed Directive on Environmental
Liability on January 23, 2003, which is currently under consideration within the
European Parliament and Council. The proposal seeks to implement a strict
liability approach for damage to biodiversity from high-risk operations.
The Commission's Clean Air for Europe Programme aims to conduct a review of
the health and environmental effects of air pollution and predicted European Air
Quality up to 2020. It will also examine cost-effective solutions to any
residual air pollution problems, firstly in a strategy document (expected in
2005) and secondly in legislative proposals (expected between 2005 and 2007)
which may include revisions to current regulations on air quality limit values,
fuel quality standards, plant emission standards and totally new regulations. BP
through various industry bodies is among the various stakeholders contributing
to the scientific activities underpinning this work.
PROPERTY, PLANTS AND EQUIPMENT
BP has freehold and leasehold interests in real estate in numerous
countries throughout the world, but no one individual property is significant to
the Group as a whole. See Exploration and Production under this heading for a
description of the Group's significant reserves and sources of crude oil and
natural gas. Significant plans to construct, expand or improve specific
facilities are described under each of the business headings within this Item.
Page 68
ORGANIZATIONAL STRUCTURE
The significant subsidiary undertakings of the Group at December 31, 2002
and the Group percentage of ordinary share capital (to nearest whole number) are
set out below. The principal country of operation is generally indicated by the
company's country of incorporation or by its name. Those held directly by the
Company are marked with an asterisk (*), the percentage owned being that of the
Group unless otherwise indicated.
Country of
Subsidiary undertakings % incorporation Principal activities
----------------------- ------------- --------------------
INTERNATIONAL
BP Chemicals Investments 100 England Chemicals
BP Exploration Co. 100 Scotland Exploration and production
BP International 100 England Integrated oil operations
BP Oil International 100 England Integrated oil operations
BP Shipping* 100 England Shipping
Burmah Castrol 100 England Lubricants
EUROPE
UK
BP Capital Markets 100 England Finance
BP Chemicals 100 England Chemicals
BP Oil UK 100 England Refining and marketing
Britoil (parent 15%)* 100 Scotland Exploration and production
Jupiter Insurance 100 Guernsey Insurance
FRANCE
BP France 100 France Refining and marketing and chemicals
GERMANY
Deutsche BP 100 Germany Refining and marketing and chemicals
Veba Oil 100 Germany Refining and marketing and chemicals
NETHERLANDS
BP Capital BV 100 Netherlands Finance
BP Nederland 100 Netherlands Refining and marketing
NORWAY
BP Norway 100 Norway Exploration and production
SPAIN
BP Espana 100 Spain Refining and marketing
MIDDLE EAST
BP Egypt 100 USA Exploration and production
BP Egypt Gas 100 USA Exploration and production
FAR EAST
INDONESIA
BP Kangean 100 Indonesia Exploration and production
SINGAPORE
BP Singapore Pte* 100 Singapore Refining and marketing
Page 69
Country of
Subsidiary undertakings % incorporation Principal activities
----------------------- ------------- ---------------------
AFRICA
BP Southern Africa 75 South Africa Refining and marketing
AUSTRALASIA
AUSTRALIA
BP Australia 100 Australia Integrated oil operations
BP Developments Australia 100 Australia Exploration and production
BP Finance Australia 100 Australia Finance
NEW ZEALAND
BP Oil New Zealand 100 New Zealand Marketing
WESTERN HEMISPHERE
CANADA
BP Canada Energy 100 Canada Exploration and production
TRINIDAD
Amoco Trinidad (LNG) B.V. 100 Netherlands Exploration and production
BP of Trinidad and Tobago 90 USA Exploration and production
USA
Atlantic Richfield Co. 100 USA (
BP America* 100 USA (
BP America Production Company 100 USA ( Exploration and production,
BP Amoco Chemical Company 100 USA ( gas, power and renewables,
BP Company North America 100 USA ( refining and marketing,
BP Corporation North America 100 USA ( pipelines and chemicals
BP Products North America 100 USA (
BP West Coast Products 100 USA (
Standard Oil Co. 100 USA (
Page 70
ITEM 5 -- OPERATING AND FINANCIAL REVIEW AND PROSPECTS
GROUP OPERATING RESULTS
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
($ million except per
share amounts)
Turnover.................................................. 178,721 174,218 148,062
Reconciliation of historical cost and
pro forma results
Historical cost profit for the year....................... 6,845 6,556 10,120
Inventory holding (gains) losses.......................... (1,104) 1,900 (728)
-------- -------- ---------
Replacement cost profit for the year...................... 5,741 8,456 9,392
Exceptional items, net of tax............................. (1,043) (165) (78)
-------- -------- ---------
Replacement cost profit before exceptional items (a)...... 4,698 8,291 9,314
Special items, net of tax................................. 1,443 683 1,257
Acquisition amortization.................................. 2,574 2,585 1,612
-------- -------- ---------
Pro forma result adjusted for special items............... 8,715 11,559 12,183
======== ======== =========
Per ordinary share (cents)
Historical cost profit.................................. 30.55 29.21 46.77
Replacement cost profit before exceptional items........ 20.97 36.95 41.15
Pro forma result adjusted for special items............. 38.90 51.51 56.29
Dividends per ordinary share (cents)...................... 24.00 22.00 20.50
----------
(a) Refer to Item 3 -- Key Information -- Selected Financial Information for
further information on replacement cost measures.
The financial information for 2001 and 2000 has been restated to reflect
(i) the adoption by the Group of UK Financial Reporting Standard No. 19 (FRS 19)
'Deferred Tax' with effect from January 1, 2002; and (ii) the transfer of the
solar, renewables and alternative fuels activities from Other Businesses and
Corporate to Gas and Power on January 1, 2002. To reflect this transfer, Gas and
Power was renamed Gas, Power and Renewables from the same date. Comparative
information has been restated. For further information see Item 18 -- Financial
Statements -- Notes 45 and 46.
On February 1, 2002, BP acquired a 51% interest in and operational control
of Veba. Veba has been fully consolidated within the Group's results from this
date. The remaining 49% of Veba was acquired on June 30, 2002.
During 2000 the Company acquired ARCO and Burmah Castrol and also purchased
most of ExxonMobil's assets used by the fuels refining and marketing operation
in Europe (the 2000 portfolio changes). BP's turnover and results in 2000
reflect the inclusion of ARCO and Burmah Castrol and the full consolidation of
the European fuels joint venture from April 14, July 7 and August 1, 2000,
respectively.
The 2000 portfolio changes have a significant effect on year on year
comparisons: 2002 and 2001 include a full year; 2000 includes ARCO, Burmah
Castrol and the full consolidation of the European fuels business for varying
parts of the year.
The trading environment was challenging during 2002, with natural gas
prices and refining margins significantly weaker than in the previous year,
owing to the global economic slowdown. Demand improved in most parts of the
business after the first half of the year but economic conditions remained
sluggish. The adverse business conditions had the greatest impact on refining
and marketing. Worldwide refining margins were depressed for much of the year,
at nearly half the average level of 2001. Margins in Chemicals were at levels
similar to the bottom of previous cycles.
Page 71
Oil prices were volatile in 2002. The Brent price ranged from around $18
per barrel to above $31 per barrel. The crude oil price increased during the
second half of the year, partly reflecting a 'war premium'. Brent prices
averaged $25.03 per barrel compared with $24.44 per barrel in 2001. Natural gas
prices in the USA were on average lower than in 2001, at around $3.36 per mmbtu
compared with $3.96 per mmbtu, owing to a large surplus of natural gas in
storage during the 2001-2002 heating season. Cold weather and the start of a
decline in domestic production in the USA brought about a rise in price to
around $5 per mmbtu towards the end of 2002.
The trading environment was generally favourable in the first half of 2001.
Natural gas and oil prices remained high until clear evidence of the global
economic slowdown emerged after the first few months. Business conditions
deteriorated in the second half and remained weak following the events of
September 11. Oil prices were 15% down against the levels seen in 2000; refining
margins were weak; retailing was fiercely competitive; and in the chemicals
sector, margins were at levels below those seen at the bottom of the previous
business cycle.
The trading environment was strong in 2000, with high oil and gas prices
and significantly improved refining margins being partly offset by pressure on
marketing margins from higher product costs and the weaker chemicals
environment, owing to high feedstock costs and a weak euro.
Hydrocarbon production increased by 2.9% in 2002 against a target of 5.5%,
reflecting production growth of 4.5% for crude oil and 0.9% for natural gas.
Total hydrocarbon production increased by 5.5% in 2001 compared with 2000.
The increase in turnover for 2002 reflects production and sales volume
increases and higher crude oil realizations, partly offset by lower natural gas
prices. The increase in turnover between 2000 and 2001 reflects a full year's
contribution from the 2000 portfolio changes and higher natural gas sales
volumes partly offset by the effect of lower oil prices.
Replacement cost profit before exceptional items (which excludes inventory
holding gains and losses) was $4,698 million in 2002 compared with $8,291
million in 2001 and $9,314 million in 2000.
The reduction in 2002 replacement cost profit before exceptional items
compared with 2001 reflects the challenging environment, although the impact of
lower natural gas prices and refining margins was partly offset by higher
production and sales volumes, lower costs in certain businesses, improved
Chemicals performance and contributions from Veba and other acquisitions.
The decline in replacement cost profit before exceptional items for 2001
compared with 2000 primarily reflects lower oil prices and chemicals margins,
partly offset by the inclusion of the first full year of contributions from the
2000 portfolio additions.
Owing to the significant acquisitions that took place in 2000, in addition
to its reported results, BP is presenting pro forma results adjusted for special
items in order to enable shareholders to assess current performance in the
context of our past performance and against that of our competitors. The pro
forma result, adjusted for special items, was $8,715 million in 2002 compared
with $11,559 million in 2001 and $12,183 million in 2000. The pro forma result,
adjusted for special items, has been derived from the Group's reported UK GAAP
accounting information but is not in itself a recognized UK or US GAAP measure.
The pro forma result is replacement cost profit before exceptional items
excluding acquisition amortization. Acquisition amortization refers to
depreciation relating to the fixed asset revaluation adjustments and
amortization of goodwill consequent upon the ARCO and Burmah Castrol
acquisitions in 2000. Goodwill and fixed asset revaluation adjustments arising
from subsequent transactions has not been included in acquisition amortization.
Page 72
The following tables provide a breakdown of pro forma results and reconcile
those results to replacement cost operating profit by operating segment.
Pro forma
result
adjusted
for
Reconciliation of replacement cost profit/loss to Acquisition Special special
pro forma result adjusted for special items Reported amortization (a) items (b) items
-------- ----------- -------- --------
($ million)
Year ended December 31, 2002
Exploration and Production.................................... 9,206 1,780 1,019 12,005
Gas, Power and Renewables..................................... 354 -- 30 384
Refining and Marketing........................................ 872 794 415 2,081
Chemicals..................................................... 515 -- 250 765
Other businesses and corporate................................ (701) -- 186 (515)
------ ------ ------ ------
Replacement cost operating profit............................. 10,246 2,574 1,900 14,720
Interest expense.............................................. (1,279) -- 15 (1,264)
Taxation...................................................... (4,217) -- (456) (4,673)
Minority shareholders' interest............................... (52) -- (16) (68)
------ ------ ------ ------
Replacement cost profit before exceptional items.............. 4,698 2,574 1,443 8,715
====== ====== ======
Exceptional items before tax.................................. 1,168
Taxation on exceptional items................................. (125)
------
Replacement cost profit after exceptional items............... 5,741
Inventory holding gains (losses).............................. 1,104
------
Historical cost profit........................................ 6,845
======
Year ended December 31, 2001(c)
Exploration and Production.................................... 12,361 1,815 322 14,498
Gas, Power and Renewables..................................... 488 -- -- 488
Refining and Marketing........................................ 3,573 770 487 4,830
Chemicals..................................................... 128 -- 114 242
Other businesses and corporate................................ (523) -- 73 (450)
------ ------ ------ ------
Replacement cost operating profit............................. 16,027 2,585 996 19,608
Interest expense.............................................. (1,670) -- 62 (1,608)
Taxation...................................................... (6,005) -- (375) (6,380)
Minority shareholders' interest............................... (61) -- -- (61)
------ ------ ------ ------
Replacement cost profit before exceptional items.............. 8,291 2,585 683 11,559
====== ====== ======
Exceptional items before tax.................................. 535
Taxation on exceptional items................................. (370)
------
Replacement cost profit after exceptional items............... 8,456
Inventory holding gains (losses).............................. (1,900)
------
Historical cost profit........................................ 6,556
======
Page 73
Pro forma
result
adjusted
for
Reconciliation of replacement cost profit/loss to Acquisition Special special
pro forma result adjusted for special items Reported amortization (a) items (b) items
-------- ----------- -------- --------
($ million)
Year ended December 31, 2000(c)
Exploration and Production.................................... 13,972 1,214 524 15,710
Gas, Power and Renewables..................................... 532 -- -- 532
Refining and Marketing........................................ 3,486 477 595 4,558
Chemicals..................................................... 760 -- 276 1,036
Other businesses and corporate................................ (1,071) -- 488 (583)
------ ------ ------ ------
Replacement cost operating profit............................. 17,679 1,691 1,883 21,253
Interest expense.............................................. (1,770) -- 111 (1,659)
Taxation...................................................... (6,506) -- (737) (7,243)
Minority shareholders' interest............................... (89) (79) -- (168)
------ ------ ------ ------
Replacement cost profit before exceptional items.............. 9,314 1,612 1,257 12,183
====== ====== ======
Exceptional items before tax.................................. 220
Taxation on exceptional items................................. (142)
------
Replacement cost profit after exceptional items............... 9,392
Inventory holding gains (losses).............................. 728
------
Historical cost profit........................................ 10,120
======
----------
(a) Acquisition amortization refers to depreciation relating to the fixed asset
revaluation adjustment and amortization of goodwill consequent upon the
ARCO and Burmah Castrol acquisitions in 2000.
(b) The special items refer to charges and credits reported in the year.
(c) 2000 and 2001 have been restated to reflect the adoption of FRS 19 and the
transfer of the solar, renewables and alternative fuels activities from
Other businesses and corporate to Gas, Power and Renewables.
Acquisition amortization for 2002 was $2,574 million compared with $2,585
million in 2001 and $1,612 million in 2000.
Page 74
We present special items to provide a better understanding of trading
performance unaffected by significant impairment, restructuring, integration and
other charges and credits. The special items for 2002, 2001 and 2000 are shown
in the table below.
Years ended December 31,
----------------------------------
Special items 2002 2001 2000
-------- -------- ---------
($ million)
Impairment charges and asset write-downs......................... 985 175 242
Restructuring, integration and rationalization costs (a)......... 774 761 1,408
Insurance claim.................................................. (184) -- --
Vacant space provision........................................... 140 -- --
Pipeline incident................................................ 62 -- --
Litigation....................................................... 55 60 63
Environmental charges............................................ 46 -- 170
Other............................................................ 22 -- --
-------- -------- ---------
1,900 996 1,883
Interest-- bond redemption charges............................... 15 62 111
-------- -------- ---------
Total special items before tax................................... 1,915 1,058 1,994
Taxation......................................................... (456) (375) (737)
Minority shareholders' interest.................................. (16) -- --
-------- -------- ---------
Total special items after tax.................................... 1,443 683 1,257
======== ======== =========
----------
(a) Refer to 'Business Operating Results' in this item for further information
on restructuring integration and rationalization costs.
The historical cost profit for 2002 was $6,845 million including inventory
holding gains of $1,104 million and net exceptional gains of $1,168 million
($1,043 million after tax) in respect of net profits on the sale of fixed assets
and businesses or termination of operations. For 2001, the historical cost
profit was $6,556 million after inventory holding losses of $1,900 million and
including net exceptional gains of $535 million ($165 million after tax) in
respect of net profits on the sale of fixed assets and businesses or termination
of operations. The historical cost profit for 2000 was $10,120 million,
including inventory holding gains of $728 million and net exceptional gains of
$220 million ($78 million after tax) in respect of net profits on the sale of
fixed assets and businesses or termination of operations.
Employee numbers increased slightly during 2002, mainly as a result of the
Veba acquisition. 2001 increases primarily related to the acquisition of Bayer's
50% interest in Erdoelchemie, the Solvay transaction and the inclusion of the
Burmah Castrol chemicals businesses previously held for sale, were partly offset
by downstream rationalization and a further decrease in former ARCO employees.
The acquisitions of ARCO and Burmah Castrol in 2000 increased our employee
numbers by approximately 25,000.
Return on average capital employed (ROACE) is one measure used to assess
BP's current performance compared with prior years and the performance of our
competitors. The decrease in replacement cost ROACE for 2002 and 2001 compared
with the prior years is due to lower profits together with higher average
capital employed. Increases in average capital employed are mainly due to
acquisitions and upstream investment.
Page 75
Years ended December 31,
--------------------------------
Return on average capital employed (ROACE) 2002 2001 2000
------ ------- ------
($ million)
Replacement cost basis
Replacement cost profit before exceptional items................. 4,698 8,291 9,314
Interest (a)..................................................... 602 798 886
Minority shareholders' interest.................................. 52 61 89
------- ------- -------
5,352 9,150 10,289
======= ======= =======
Average capital employed (b)..................................... 89,616 87,259 76,068
ROACE............................................................ 6% 10% 14%
------- ------- -------
Pro forma and special items adjustments
Acquisition amortization......................................... 2,574 2,585 1,691
Special items (post tax)......................................... 1,449 643 1,185
Average capital employed acquisition adjustment (c).............. 17,777 20,739 12,939
ROACE - Pro forma basis adjusted for special items (d)........... 13% 19% 21%
------- ------- -------
Historical cost basis
Historical cost profit after exceptional items................... 6,845 6,556 10,120
Interest......................................................... 602 798 886
Minority shareholders' interest.................................. 77 61 89
------- ------- -------
7,524 7,415 11,095
======= ======= =======
Average capital employed (b)..................................... 89,616 87,259 76,068
ROACE............................................................ 8% 8% 15%
----------
(a) For the ROACE calculation, interest expense excludes interest on debt of
joint ventures and associated undertakings as well as the unwinding of the
discount on provisions and the effect of changes in the discount rate on
provisions, and is on a post-tax basis using a deemed tax rate equal to the
US statutory tax rate.
(b) Capital employed is defined as net assets plus total finance debt. As the
acquisition of ARCO was completed in April 2000 and Burmah Castrol in July
2000, the return on average capital employed for 2000 has been calculated
as the average of the four discrete quarters. Average capital employed was
derived from the quarterly averages.
(c) Acquisition adjustment refers to the fixed asset revaluation adjustment and
goodwill consequent upon the ARCO and Burmah Castrol acquisitions.
(d) Based on the pro forma result adjusted for special items and capital
employed excluding the fixed asset revaluation adjustment and goodwill
resulting from the ARCO and Burmah Castrol acquisitions.
Years ended December 31,
--------------------------------
Capital expenditure and acquisitions (a) 2002 2001 2000
------ ------ ------
($ million)
Exploration and Production...................................... 9,266 8,627 6,383
Gas, Power and Renewables....................................... 335 485 376
Refining and Marketing.......................................... 2,682 2,386 2,369
Chemicals....................................................... 810 1,446 1,585
Other businesses and corporate.................................. 228 256 458
------- ------- -------
Capital expenditure............................................. 13,321 13,200 11,171
Acquisitions (a)................................................ 5,790 924 36,442
------- ------- -------
Capital expenditure and acquisitions............................ 19,111 14,124 47,613
Disposals (b)................................................... (6,782) (2,903) (11,362)
------- ------- -------
Net Investment.................................................. 12,329 11,221 36,251
======= ======= =======
----------
(a) 2002 includes $5,038 million for the Veba acquisition. 2000 includes
$27,506 million for the ARCO acquisition and $4,909 million for the Burmah
Castrol acquisition.
(b) 2000 includes $6,803 million proceeds from the sale of ARCO assets.
Page 76
Capital expenditure and acquisitions in 2002, 2001 and 2000 amounted to
$19,111 million, $14,124 million and $47,613 million, respectively. Acquisitions
during 2002 included Veba, an additional 15% interest in Sidanco and several
minor acquisitions. Acquisitions during 2001 included the purchase of Bayer's
50% interest in Erdoelchemie and a number of minor acquisitions. Expenditure for
the year 2000 included the acquisition of ARCO, Burmah Castrol, the ExxonMobil
share of the European Joint Venture and the minority interest in Vastar,
interests in PetroChina and Sinopec, and ExxonMobil's aviation lubricants
business. Excluding acquisitions, capital expenditure for 2002 was $13,321
million compared with $13,200 million for 2001.
Our investment strategy for 2003 to 2007 is focused on developing five new
upstream profit centres -- in the Deepwater Gulf of Mexico, Trinidad,
Azerbaijan, Angola and Asia Pacific LNG. We believe the Russian joint venture,
TNK-BP, should generate sufficient cash to finance its investment programme and
it is not expected to need additional funding from its shareholders.
Exceptional Items
For 2002, net exceptional gains, consisting of the profit or loss on sale
of fixed assets and businesses or termination of operations, were $1,168 million
before tax. These include gains from disposal of interests in Ruhrgas and
Colonial Pipeline, the sale of a US downstream electronic payment system, and a
gain on the redemption of certain preferred limited partnership interests BP
retained following the Altura Energy common interest disposal in 2000 in
exchange for BP loan notes held by the partnership. These items were partly
offset by provisions for losses on the sale of certain upstream interests
announced in early 2003.
Net exceptional gains were $535 million before tax in 2001. These
represented the profits from the sale of the Group's interest in Vysis; the
refineries at Mandan, North Dakota, and Salt Lake City, Utah; the Group's
interest in the Alliance and certain other pipeline systems in the USA; and BP's
interest in the Kashagan discovery in Kazakhstan, partly offset by losses mainly
related to the sale or closure of certain chemicals activities.
In 2000, the net exceptional gains of $220 million before tax related
mainly to disposal profits on the sale of the Group's common interest in Altura
Energy, the sale of the Alliance refinery and the divestment of exploration and
production interests in Trinidad, the UK and the USA, partly offset by the loss
on the sale of certain Venezuelan upstream interests and on the subvention of
Singapore Aromatics Company bank loans in connection with the closure of our
joint venture.
Interest Expense
Interest expense in 2002 was $1,279 million compared with $1,670 million in
2001 and $1,770 million in 2000. These amounts included special charges of $15
million, $62 million and $111 million respectively, arising from the early
redemption of bonds. After adjusting for these special charges, the decrease in
Group interest expense in 2002 compared with 2001 primarily reflects lower
interest rates. The decrease in 2001 compared with 2000 mainly reflects lower
interest rates, partly offset by the impact of revaluing environmental and other
provisions at a lower interest rate.
Taxation
The charge for corporate taxes in 2002 was $4,342 million, compared with
$6,375 million in 2001 and $6,648 million in 2000. The effective rate on
historical cost profit was 39% in 2002, 49% in 2001 and 39% in 2000. The lower
rate in 2002 reflects non-taxable inventory holding gains in 2002 compared with
inventory holding losses in 2001. The higher rate in 2001 compared with 2000
reflects the effect of a full year of acquisition amortization (which is
non-deductible for tax purposes) together with non-deductible inventory holding
losses.
Page 77
The effective rate on replacement cost profit before exceptional items was
47% compared with 42% in 2001 and 41% in 2000. The increase in the rate for 2002
compared with 2001 reflects the ratably greater effect of acquisition
amortization on lower pre-tax income in 2002, together with the $355 million
charge in the second quarter to increase the North Sea deferred tax provision
for the supplementary UK tax rate, partly offset by higher tax relief on asset
impairment charges and related restructuring. The higher rate in 2001 was due to
the full-year effect of the ARCO and Burmah Castrol acquisition amortization
charge (which is non-deductible for tax purposes).
Dividends and Share Repurchases
The total dividends announced for 2002 were $5,375 million, compared with
$4,935 million in 2001 and $4,625 million in 2000. Dividends per share for 2002
were 24.00 cents, compared with 22.00 cents per share in 2001 (an increase of
9.1%) and 20.50 cents per share in 2000 (an increase of 7.3% over 2000). The
board sets the dividend based on a balance of factors. It considers present
earnings, together with long-term growth prospects, cash flow and the Group's
competitive position.
BP intends to continue the operation of the Dividend Reinvestment Plan
(DRIP) for shareholders who wish to receive their dividend in the form of shares
rather than cash. The BP Direct Access Plan for US and Canadian investors also
includes a dividend reinvestment feature.
As part of giving a return to shareholders, one of the steps we take from
time to time is to repurchase our own shares. During 2002, a total of 100
million shares were repurchased and cancelled at a cost of $750 million. The
repurchased shares had a nominal value of $25 million and represented 0.4% of
ordinary shares in issue at the end of 2001. At that time the Company still had
shareholder approval, subject to conditions, for the repurchase of a further 2.1
billion Ordinary Shares. Since the inception of the share repurchase programme
in 2000, 476 million shares have been repurchased and cancelled at a cost of
$4.1 billion. BP's present intention is to spend up to $2 billion on further
repurchases of its own shares, subject to market conditions and continuing
support at the April 2003 Annual General Meeting.
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 $10,246 million in 2002, $16,027
million in 2001 and $17,679 million in 2000. Performance of operating segments
is evaluated by management on replacement cost operating profit or loss. Segment
results are discussed in the following pages on this basis.
Page 78
Exploration and Production
Years ended December 31,
----------------------------
2002 2001 2000
-------- -------- ---------
Turnover......................................... ($ million) 25,753 28,229 30,942
Total replacement cost operating profit.......... ($ million) 9,206 12,361 13,972
Results included:
Exploration expense............................ ($ million) 644 480 599
Key statistics:
Average BP crude oil realizations (a).......... ($ per barrel) 22.69 22.50 26.63
Average West Texas Intermediate oil price...... ($ per barrel) 26.14 25.89 30.38
Average Brent oil price........................ ($ per barrel) 25.03 24.44 28.44
Average BP US natural gas realizations......... ($ per thousand cubic feet) 2.63 3.99 3.72
Average Henry Hub gas price (b)................ ($ per thousand cubic feet) 3.22 4.26 3.90
Crude oil production (net of royalties) (c)...... (mb/d) 2,018 1,931 1,928
Natural gas production (net of royalties) (c).... (mmcf/d) 8,707 8,632 7,609
Total production (net of royalties) (c) (d)...... (mboe/d) 3,519 3,419 3,240
----------
(a) Crude oil and natural gas liquids.
(b) Henry Hub First of Month Index.
(c) Includes BP's share of associated undertakings.
(d) 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.
Turnover for 2002 was $25,753 million compared with $28,229 million in 2001
and $30,942 million in 2000. The decrease in 2002 was mainly due to lower
natural gas prices, which more than offset the effect of higher production and
crude oil realizations. The lower turnover in 2001 compared with 2000 reflected
the impact of lower oil and natural gas prices, partly offset by higher
production, in part through the inclusion of ARCO for a full year.
The replacement cost operating profit for 2002 was $9,206 million compared
with $12,361 million in 2001 and $13,972 million in 2000. These results are
after charging special items of $1,019 million, $322 million and $524 million
respectively; and depreciation and amortization arising from the fixed asset
revaluation adjustment and goodwill consequent upon the ARCO acquisition of
$1,780 million, $1,815 million and $1,214 million respectively. The year 2002
includes special charges of $686 million and accelerated acquisition
amortization of $405 million related to the impairments of Shearwater in the
North Sea, Rhourde El Baguel in Algeria, LL652 and Boqueron in Venezuela,
Pagerungan in Indonesia and Badami in Alaska, following full technical
reassessments and evaluations of future investment opportunities. All these
fields continued in operation. In addition, there were special restructuring
charges of $184 million relating to significant restructuring to reposition the
business in North America and the North Sea, $94 million for the write-off of
our Gas to Liquids demonstration plant in Alaska and $55 million of litigation
costs. The special restructuring costs comprised $145 million of severance, $19
million repatriation and other costs of $20 million, which were mostly settled
in 2002.
Special items for 2001 included a $175 million impairment of our
partner-operated Venezuelan Lake Maracaibo operations, following a technical
reassessment, $77 million additional severance costs which related to US pension
and benefits incurred in respect of ARCO terminations and were settled in 2001,
$60 million litigation and $10 million restructuring costs related to the
Grangemouth operating site in Scotland.
Page 79
The special charges of $524 million in 2000 comprise mainly ARCO and Vastar
integration costs. The restructuring cost element relating to rationalization
following the ARCO and Vastar acquisitions totalled $390 million comprising $188
million severance, $18 million asset write-downs, $59 million office closures,
$26 million information technology alignment and $99 million other restructuring
costs. With the exception of the non-cash asset write-downs, the costs were
mainly settled in 2000. Other special items in 2000 were costs incurred in
relation to the realignment of the partner interests in Alaska of $50 million
and other costs of $84 million that mainly relate to litigation settlements.
In assessing the value in use of potentially impaired assets, a discount
rate of 9% has been used, as well as a Brent oil price of $20 per barrel and a
Henry Hub gas price of $3.20 per mmbtu, which represents an average price
achieved over the past ten years. The information in Item 18 -- Financial
Statements -- Supplementary Oil and Gas Information -- Standardized measures of
discounted future net cash flows and changes therein relating to proved oil and
gas reserves was prepared using a discount rate of 10% and a year-end Brent oil
price of $30.38 per barrel and a Henry Hub gas price of $4.75 as required by
FASB Statement of Financial Accounting Standards No. 69 -- Disclosures about Oil
and Gas Producing Activities.
The 2002 decrease in replacement cost operating profit reflects production
growth of 4.5% for crude oil and 0.9% for natural gas (2.9% overall), a 4%
decrease in unit lifting costs and slightly higher crude oil realizations, which
were more than offset by significantly lower natural gas realizations.
Lower 2001 replacement cost operating profit compared with 2000 reflects
the oil price decrease of over $4 per barrel, partly offset by operational
improvements and the inclusion of ARCO for the whole year, compared to only
around nine months (from April 14) in 2000 and other portfolio changes.
Finding and development costs in 2002 averaged $4.14 per barrel of oil
equivalent, compared with $3.68 in 2001 and $3.29 in 2000. The increase reflects
the higher costs incurred on the deepwater developments. Finding costs were
$0.79 per barrel of oil equivalent, compared with $0.54 in 2001 and $1.22 in
2000. On a three year rolling average basis, the finding costs were $0.78 per
barrel of oil equivalent for 2002 compared with $0.82 for 2001 and $1.21 for
2000 reflecting the significant discoveries made during the period 1999 to 2001.
Unit lifting costs were $2.60 per barrel of oil equivalent compared with $2.70
in 2001 and $2.60 in 2000, reflecting the sustained cost savings that have been
achieved since the merger of BP and Amoco.
In 2002, a number of new fields started producing, the most significant of
which were King, King's Peak, Horn Mountain, Aspen and Princess in the Deepwater
Gulf of Mexico. In Trinidad, production of natural gas was increased from the
existing fields to supply the second LNG train, which started up in August. In
Azerbaijan, the Chirag field contributed steady production. In Angola,
production from Girassol built up to its plateau level after starting up at the
end of 2001. Production started at the Lan Tay field in Vietnam in November. In
our other operations, production from Northstar in Alaska also built up to
plateau level, and there was strong performance from Australia and Egypt owing
to higher natural gas sales.
These production increases in 2002 were partly offset by a number of
factors, including lower natural gas demand resulting from warm weather in the
UK, OPEC reductions, severe storm patterns in the Gulf of Mexico, the general
strike in Venezuela and operational problems in Alaska and the UK.
Exploration successes in 2002 included discoveries in the Gulf of Mexico,
Trinidad, Angola and Egypt. The Plutao field is the first ultra-deepwater
discovery offshore Angola. We were awarded new licences in the Gulf of Mexico,
Norway and Russia.
Page 80
We made two major natural gas discoveries off the coast of Trinidad in
2002, in Iron Horse and Red Mango No. 2, taking the total to four new
discoveries in three years. Along with the advantages of scale, improved
liquefaction technology has reduced costs in Trinidad by nearly 30%, compared
with LNG plants built elsewhere in the 1980s and early 1990s. Continuing
technology developments and an increase in plant scale allow us to target a
further 25% cost reduction by the end of the decade. This should enable us to
compete successfully in new LNG markets. We have led our major competitors in
the number of large discoveries during the past five years.
The reserve replacement ratio for 2002 was 175% with 2.0 billion barrels of
oil equivalent booked through discoveries, extensions, revisions and improved
recovery. Total hydrocarbon production for 2001 increased 5.5% and the reserve
replacement ratio was 191% with 2.2 billion barrels of oil equivalent booked
through extensions, discoveries, revisions and improved recovery. Reserve
replacement has exceeded production for ten consecutive years at an average
ratio of 145% over that period.
In support of growth, 2002 capital expenditure and acquisitions at $9.7
billion was 9% higher than the 2001 level of $8.9 billion; 2001 was 52% higher
than the 2000 level of $6.4 billion. Excluding acquisitions, capital expenditure
in 2002 was $9.3 billion compared with $8.6 billion in 2001 and $6.4 billion in
2000.
Our aim is to balance growth and returns by allocating investment to
projects with the highest expected returns, ranked globally; by improving
operating efficiency; and by selling assets that are not strategic to us and
have greater value to others. We have already divested or agreed to divest
assets amounting to over $3 billion in 2003.
We made significant progress in 2002 in building up our five new profit
centres. Late in 2002, development started at the Atlantis field in the
Deepwater Gulf of Mexico. Atlantis joined four other fields -- Na Kika,
Holstein, Mad Dog and Thunder Horse - that are also being developed in the Gulf.
Construction of the Mardi Gras pipeline system, to handle the oil and gas
production from BP's new fields in the Gulf, continues and is on track.
We expect to invest around $20 billion in the five new profit centres
during the period 2003 to 2007; no investment is currently planned for the
proposed Russian joint venture. Building these profit centres requires a
relatively high level of capital spending over the period 2002 to 2004.
Gas, Power and Renewables
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
Turnover............................................... ($ million) 37,357 39,442 21,203
Total replacement cost operating profit................ ($ million) 354 488 532
Total natural gas sales volumes (a).................... (mmcf/d) 21,621 18,794 14,471
----------
(a) Includes marketing, trading and supply sales.
On January 1, 2002, the solar, renewables and alternative fuels activities
were transferred from Other Businesses and Corporate to Gas and Power. To
reflect this transfer, Gas and Power was renamed Gas, Power and Renewables from
the same date and comparative information has been restated.
Turnover was $37,357 million in 2002 compared with $39,442 million in 2001,
as higher natural gas sales volumes were more than offset by lower prices,
particularly in North America. The increase from $21,203 million in 2000 is
mainly attributable to higher sales volumes in the natural gas marketing and
trading business.
Page 81
Replacement cost operating profit for 2002 was $354 million compared with
$488 million in 2001 and $532 million in 2000. The result for 2002 includes a
special charge of $30 million related to the impairment of a cogeneration power
plant under construction in the UK. The impairment is the result of a
significant fall in power prices in the UK over the last two years. The decrease
in profit in 2002 is due to a lower contribution from Ruhrgas and a weaker
marketing and trading environment, partly offset by better performance in the
NGL business and increased natural gas sales volumes which were up by 15%. The
sale of the Ruhrgas shareholding was effective August 1, 2002. The 2001 result
is down on 2000 due to a lower contribution from NGLs, partly offset by better
results from marketing and trading and Ruhrgas. In 2000 the NGL business
benefited from exceptionally strong margins.
Natural gas sales increased from 14.5 billion cubic feet per day in 2000 to
18.8 billion cubic feet per day in 2001, and increased further to 21.6 billion
cubic feet per day in 2002.
Although gas sales volumes increased 15% in 2002, margins in the industry
were less favourable than in 2001, which had benefited from a period of unusual
volatility in North America. Margins improved across our NGLs business through a
combination of operating efficiency, lower costs and favourable market
conditions. We also achieved more than 20% growth in sales of solar systems and
panels, from 55 megawatts in 2001 to 67 megawatts in 2002, with an overall
improvement in total gross margin against increasing competitive pressure.
Capital expenditure and acquisitions for 2002 was $408 million compared
with $492 million in 2001 and $376 million in 2000.
Refining and Marketing
Years ended December 31,
--------------------------------
2002 2001 2000 (a)
-------- -------- ---------
Turnover............................................... ($ million) 125,836 120,233 107,883
Total replacement cost operating profit................ ($ million) 872 3,573 3,486
Global Indicator Refining Margin (b)................... ($/bbl) 2.11 4.06 4.22
Refinery throughputs................................... (mb/d) 3,103 2,929 2,916
Total marketing sales ................................. (mb/d) 4,180 3,797 3,420
----------
(a) Includes BP's share of the BP/Mobil European joint venture until August 1,
2000.
(b) The Global Indicator Refining Margin is the average of seven regional
indicator margins weighted for BP's crude refining capacity in each region.
Each regional indicator margin is based on a single representative crude
with product yields characteristic of the typical level of upgrading
complexity.
Turnover for 2002 was $125,836 million compared with $120,233 million for
2001 and $107,883 million for 2000. The increase in turnover for 2002 compared
with 2001 is due primarily to volume increases from the Veba acquisition.
Results for Veba have been included from February 1, 2002. The increase in
turnover for 2001 compared with 2000 principally reflected the acquisitions of
ARCO and Burmah Castrol and the consolidation of the European fuels business
during 2000. Turnover for 2000 included ARCO from April 14, Burmah Castrol from
July 7 and the European fuels business from August 1. Turnover for 2001 includes
these businesses for the full year.
The replacement cost operating profit for 2002 was $872 million compared
with $3,573 million in 2001 and $3,486 million in 2000. These results are after
special charges of $415 million, $487 million and $595 million respectively; and
depreciation and amortization arising from the fixed asset revaluation
adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions
of $794 million, $770 million and $477 million, respectively. Special items for
2002 included a credit related to business interruption insurance proceeds of
$184 million, as well as charges of $348 million related to Veba integration,
$132 million restructuring costs, $62 million costs associated with an Olympic
pipeline incident in 1999, a $35 million write-down of retail assets in
Venezuela and $22 million settlement costs associated with a pre-acquisition
ARCO US MTBE supply contract. Special charges in 2001 comprised $334 million
Castrol integration costs, $101 million rationalization costs in the downstream
European commercial business and Grangemouth restructuring and $52 million
additional severance charges mainly related to former ARCO employees. The
special charges in 2000 mainly comprised ARCO and Burmah Castrol integration
costs, rationalization costs following the BP and Amoco merger, environmental
charges and litigation costs.
Page 82
The 2002 special charges of $348 million related to the Veba acquisition
comprised $210 million severance costs, $77 million other integration costs such
as consulting, studies and internal project teams, $24 million system
infrastructure and application costs, $22 million office consolidation and
relocation and $15 million additional synergy projects. 2002 cash outflows
related to these special charges were approximately $140 million. Integration
began in February 2002, and completion is planned in the second half of 2003.
Total costs and cash outflows are expected to be approximately $570 million,
including the full integration of the organizations, rebranding and systems
integration and alignment. The targeted synergies are $200 million per year. The
$132 million special restructuring costs are associated with several
restructuring and cost reduction initiatives during 2002 in different business
units and support functions, primarily in the USA, Western Europe and in Africa.
The largest single functional area affected was information technology. In
Venezuela an impairment review was triggered by the current political crisis and
poor business performance in 2002.
The integration of the ARCO businesses was largely completed during 2001
and primarily affected the Western USA. The anticipated downstream synergies
were achieved, resulting from cost reduction, hydrocarbon procurement and
working capital reduction. The special charges associated with the integration
were $52 million in 2001 and $109 million in 2000. The major components of the
costs were severance payments, office consolidation and information technology
infrastructure.
The integration of the Castrol businesses was mostly complete by the end of
2001. The anticipated synergies of $260 million per year, resulting from
efficiencies in supply chain and support activities, were exceeded by $20
million and delivered one year in advance. The costs associated with
restructuring, integration and rationalisation were $485 million ($334 million
in 2001 and $151 million in 2000). The majority of the costs were related to
severance payments, relocation and infrastructure.
The result for 2002 compared with 2001 reflects the impact of a halving of
worldwide refining margins with a further adverse effect from price
differentials in BP's crude oil mix, and lower US retail margins, with some
offset from European retail and the Veba contribution. Refining throughputs
increased by 6% over the prior year and marketing volumes increased by 10%,
primarily due to Veba. Excluding Veba, marketing volumes were slightly down.
Retail shop sales grew 60% due to Veba and the increased number of BP Connect
stations, 10% excluding Veba. Retail sales grew 7% in 2002 in stores that were
also operating in 2001.
Against this difficult background, we delivered improved plant
availability, increased retail store sales and volume and margin growth in
lubricants.
The 2001 result reflects the benefit of the 2000 portfolio changes and
improved marketing volumes, offset by the effects of a larger refinery
maintenance programme. We delivered a strong performance, led in particular by
US refining in the first half of the year, where margins were very good. In both
the USA and Europe, refining margins declined in the latter part of 2001. In
September 2001, in line with our strategy, we completed the sale of refineries
at Mandan, North Dakota and Salt Lake City, Utah in the USA.
Page 83
Marketing experienced significant competitive pressures throughout 2001. We
delivered growth of 23% (7% excluding portfolio changes) in convenience store
sales and 8% in retail fuel volumes, reflecting the full-year benefit of the
2000 portfolio changes and the rollout of the new BP Connect convenience sites.
Capital expenditure and acquisitions in 2002 was $7,753 million, including
$5,038 million for the Veba acquisition, compared with $2,415 million in 2001
and $8,693 million in 2000. Excluding acquisitions, capital expenditure was
$2,682 million in 2002 compared with $2,386 million in 2001 and $2,369 million
in 2000.
Chemicals
Years ended December 31,
----------------------------
2002 2001 2000
------ ------ ------
Turnover............................................... ($ million) 13,064 11,515 11,247
Total replacement cost operating profit................ ($ million) 515 128 760
Chemicals Indicator Margin (a)......................... ($/te) 102 (b) 109 126
Production volumes (c)................................. (kte) 26,988 22,716 22,065
----------
(a) The Chemicals Indicator Margin (CIM) is a weighted average of externally
based product margins. It is based on market data collected by Nexant
(formerly Chem Systems) in their quarterly market analyses, then weighted
based on BP's product portfolio. While it does not cover our entire
portfolio, it includes a broad range of products. Among the products and
businesses covered in the CIM are the olefins and derivatives, the
aromatics and derivatives, linear alpha-olefins (LAOs), acetic acid, vinyl
acetate monomers and nitriles. Not included are fabrics and fibres, plastic
fabrications, poly alpha-olefins (PAOs), anhydrides, engineering polymers
and carbon fibers, speciality intermediates, and the remaining parts of the
solvents and acetyls businesses.
(b) Provisional. The data for the current year is based on eleven months of
actual data and one month of provisional data.
(c) Includes BP share of joint ventures, associated undertakings and other
interests in production.
Turnover has increased from $11,247 million in 2000 to $11,515 million in
2001 and to $13,064 million in 2002. The higher turnover in 2001 compared with
2000 reflects the consolidation of Erdoelchemie from May 2, 2001 partly offset
by the effect of lower prices. The increase in turnover for 2002 compared with
2001 primarily reflects higher production as a result of acquisitions, organic
growth and improved site reliability.
Replacement cost operating profit for 2002 was $515 million, compared with
$128 million in 2001 and $760 million in 2000, including special charges of $250
million, $114 million and $276 million respectively.
Page 84
Special charges for 2002 included a $140 million write-down of our
Indonesian manufacturing assets held for sale, following a review of immediate
prospects and opportunities for future growth in a highly competitive market. In
addition, there were $110 million of special integration and restructuring
costs. Special charges for 2001 include Grangemouth restructuring and costs
related to Erdoelchemie and Solvay integration. In 2000 special charges
comprised a provision against a chemicals investment in Indonesia, asset
write-downs and rationalization costs following the BP and Amoco merger.
The special charges related to integration, rationalization and
restructuring in 2002, 2001 and 2000 are the result of an ongoing segment
restructuring programme which dates back to the merger of BP and Amoco. The
costs comprise severance, asset write-downs, information technology alignment,
and various other costs. The aim of the programme is to reposition the segment
portfolio, and thus improve efficiency and performance.
The 2002 result was an increase of $387 million over 2001, in an overall
trading environment which was similar. This improvement was driven by lower
costs and increased production.
Compared with 2000, the business environment for petrochemicals was very
difficult throughout 2001 with margins at levels below those seen at the bottom
of the previous business cycle. After early plant operating problems, we
recorded lower unit costs through restructuring and improved plant performance
in the second half of 2001.
Cash fixed costs per tonne of capacity, using an index which equates 2000
costs to 100, were 81 in 2002 compared with 86 in 2001.
BP's share of production for 2002 was 26,988 thousand tonnes, up 19% on
2001, as a result of new production from existing and acquired assets.
Production for 2001 was 22,716 million tonnes, up 3% on 2000 due to new
production and acquired assets. Production for 2000 was 22,065 million tonnes.
Major restructuring continued throughout 2002 and 2001, aimed at
repositioning the portfolio and lowering the cost base. In addition to the
special charges above, the 2002 and 2001 results include further rationalization
costs of $39 million and $102 million respectively.
Capital expenditure and acquisitions in 2002 was $823 million compared with
$1,926 million in 2001 and $1,585 million in 2000. Excluding acquisitions,
capital expenditure was $810 million, $1,446 million and $1,585 million
respectively.
Other Businesses and Corporate
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
Turnover........................................... ($ million) 510 549 59
Replacement cost operating loss.................... ($ million) (701) (523) (1,071)
Other Businesses and Corporate comprises Finance, our coal and aluminium
assets, our investments in PetroChina and Sinopec, interest income and costs
relating to corporate activities worldwide.
On January 1, 2002, the solar, renewables and alternative fuels activities
were transferred to Gas, Power and Renewables. Comparative information has been
restated.
Page 85
The net cost of Other Businesses and Corporate amounted to $701 million in
2002, $523 million in 2001 and $1,071 million in 2000. These net costs include
special charges of $186 million, $73 million and $488 million respectively.
Special charges in 2002 include provisions of $140 million for future rentals on
surplus leasehold property and a charge of $46 million for environmental
liabilities in respect of a divested business. Special charges in 2001 comprise
additional severance charges mainly related to former ARCO employees. For 2000,
special charges comprised ARCO integration costs, rationalization costs
following the BP and Amoco merger and environmental charges.
Expenditure on research for 2002 was $373 million, compared with $385
million in 2001 and $434 million in 2000.
During 2000, we purchased an interest in PetroChina for $578 million and an
interest in Sinopec for $416 million.
Outlook
The trading environment was challenging during 2002. Whilst there was
little change in crude oil prices between 2001 and 2002, natural gas prices and
refining margins were significantly weaker than in the previous year and
chemicals margins remained depressed.
Crude oil prices were marginally higher in 2002 than in 2001. Dated Brent
averaged $25.03 per barrel in 2002 compared with $24.44 per barrel in 2001. OPEC
production restraint kept the market reasonably balanced despite weak oil demand
and strong growth in oil production outside OPEC. Prices were volatile moving in
a range of $18 to 32 for Brent but, in general, they trended upwards over the
course of the year.
The economic downturn and the aftermath of the September 11th terrorist
attacks took a heavy toll on the margin businesses in 2002. Refining margins
were depressed for much of the year and averaged only around half of 2001 levels
in the face of consistently high product inventories and tightening crude oil
markets. Margins in chemicals were at levels similar to the bottom of previous
cycles.
US natural gas prices (Henry Hub) averaged around $3.36 per mmbtu in 2002,
down from $3.96 per mmbtu in 2001. The mild winter of 2001/2002 and the US
economic downturn resulted in a large surplus of gas in storage at the start of
the year, which was not worked off until late in 2002. Gas prices traded at a
discount to residual fuel oil for most of the year. As with crude oil prices, US
gas prices trended upwards over the course of 2002, the low of just under
$2/mmbtu being recorded in January and the high of over $5/mmbtu being recorded
in December.
Crude oil prices have been volatile so far in 2003, with dated Brent
fluctuating between $26 and $35 in the aftermath of the supply disruption caused
by the Venezuelan general strike and as a result of the threat and subsequent
outbreak of military action in Iraq. Refining margins have strengthened in
response to falling product inventories. US natural gas prices have also been
strong in the face of a cold US winter and declining US gas production.
Chemicals margins remain under pressure.
We continue to take a cautious view about the external environment in 2003,
given the uncertain nature of the economic recovery and geopolitical
uncertainties. Whilst US gas markets look to be strongly underpinned by
supply/demand fundamentals, crude prices and refining margins remain vulnerable
to reductions in uncertainties and potential economic weakness. Chemicals
margins will be sensitive to any deterioration in economic conditions.
As of the date of filing this annual report, the outlook in all our
activities is unusually uncertain due to the unpredictable situation surrounding
Iraq.
Page 86
Environmental Expenditure
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Operating expenditure........................................ 485 436 514
Capital expenditure.......................................... 660 423 298
Clean-ups.................................................... 49 67 81
New provisions for environmental remediation................. 312 180 228
New provisions for decommissioning........................... 308 156 139
Operating and capital expenditure on the prevention, control, abatement or
elimination of air, water and solid waste pollution is often not incurred as a
discrete identifiable transaction. Instead, it forms part of a larger
transaction which includes, for example, normal maintenance expenditure. The
figures for environmental operating and capital expenditure in the table are
therefore estimates, based on the definitions and guidelines of the American
Petroleum Institute.
Operating expenditure and clean-ups for 2002 were similar to the 2001
level. Capital expenditure increased in 2002 compared with 2001, primarily as a
result of projects to reduce refinery emissions associated with our agreement
with the Environmental Protection Agency and upgrades required to meet new US
emission requirements for gasoline and highway diesel. Capital expenditures are
expected to be at levels similar to 2002 in the near term. In addition to
operating and capital expenditures, we also create provisions for future
environmental remediation. The increase in new provisions in 2002 is primarily
related to US retail sites and results from new regulations and ongoing review
of the liabilities. 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.
The extent and cost of future remediation programmes are inherently
difficult to estimate. They depend on the scale of any possible contamination,
the timing and extent of corrective actions, and also the Group's share of the
liability. Although the cost of any future remediation could be significant, and
may be material to the result of operations in the period in which it is
recognized, we do not expect that such costs will have a material effect on the
Group's financial position or liquidity. We believe our provisions are
sufficient for known requirements; and we do not believe that our costs will
differ significantly from those of other companies (with similar assets) engaged
in similar industries or that our competitive position will be adversely
affected as a result.
In addition, we make provisions to meet the cost of eventual
decommissioning of our oil- and gas-producing assets and related pipelines.
Provisions for environmental remediation and decommissioning are usually set up
on a discounted basis, as required by Financial Reporting Standard No. 12,
'Provisions, Contingent Liabilities and Contingent Assets'. Further details of
decommissioning and environmental provisions appear in Item 18 -- Financial
Statements -- Note 31. See also Item 4 -- Information on the Company --
Environmental Protection.
Insurance
The Group generally restricts its purchase of insurance to situations where
this is required for legal or contractual reasons. This is because external
insurance is not considered an economic means of financing losses for the Group.
Losses will therefore be borne as they arise rather than being spread over time
through insurance premia with attendant transaction costs. The position is
reviewed from time to time.
Page 87
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Net cash inflow from operating activities.................... 19,342 22,409 20,416
Net cash (outflow) inflow ................................... (344) 1,002 3,743
Net cash outflow for 2002 was $344 million, compared with an inflow of
$1,002 million in 2001, as lower operating cash flow and higher acquisition
spending were partly offset by lower tax payments and higher disposal proceeds.
The decrease in cash flow between 2000 and 2001 is primarily driven by higher
capital expenditure and significantly lower divestment proceeds (2000 included
proceeds from the sale of the ARCO Alaska assets).
Net cash inflow from operating activities decreased to $19,342 million in
2002 from $22,409 million in 2001 and $20,416 million in 2000. In 2002, lower
profit and higher working capital were partly offset by higher depreciation
resulting from impairments. Lower income in 2001 compared with 2000 was more
than compensated for by lower working capital requirements and higher
depreciation.
Dividends from joint ventures and associated undertakings have decreased
from $1,039 million in 2000 to $632 million in 2001 and to $566 million in 2002.
The decrease in 2002 was related to the Erdoelchemie transaction and the Altura
transaction partly offset by an increase from Watson Cogeneration. The principal
factor underlying the decrease in 2001 was the dissolution in August, 2000 of
the BP/Mobil European joint venture.
The net cash outflow from servicing of finance and returns from investments
was $911 million in 2002, $948 million in 2001 and $892 million in 2000. The
lower cash outflow in 2002 is primarily due to lower interest payments. The
higher cash outflow in 2001 compared with 2000 arises because the decrease in
interest payments was more than offset by the decrease in interest receipts.
Tax payments decreased to $3,094 million in 2002 from $4,660 million in
2001 and $6,198 million in 2000 reflecting the decline in profits across the
period and in 2000 additional taxes related to the FTC mandated disposal of
ARCO's Alaskan operations.
Payments for capital expenditures on fixed assets net of proceeds from
sales of fixed assets, amounted to $9,646 million in 2002 compared with $9,849
million in 2001 and $7,072 million in 2000. The decrease in 2002 over 2001 was
due to slightly lower capital expenditure and higher disposal proceeds. The
increase in 2001 over 2000 was mainly due to higher capital expenditure and
lower disposal proceeds.
Acquisitions and disposals of businesses produced a net cash outflow of
$1,337 million in 2002 compared with an outflow of $1,755 million in 2001, as
the impact of the Veba acquisition was more than offset by higher disposal
proceeds. Acquisitions and disposals of businesses produced a net cash outflow
of $1,755 million in 2001 compared with an inflow of $865 million in 2000
reflecting decreased acquisition activity and lower disposal proceeds. 2000
included disposal proceeds of $6,803 million, for the FTC mandated sales, which
were largely offset by the Burmah Castrol acquisition.
Overall net cash outflow for capital expenditure and acquisitions, net of
disposals, was $10,983 million compared with $11,604 million in 2001 and $6,207
million in 2000.
Dividend payments have increased to $5,264 million from $4,827 million in
2001 and $4,415 million in 2000. The increase in both years reflects the impact
of the higher dividend per share, partly offset by share repurchases.
Page 88
Financing the Group's Activities
The Group's principal commodity, oil, is priced internationally in dollars.
Group policy has been to minimize economic exposure to currency movements by
financing operations with US dollar debt wherever possible, otherwise by using
currency swaps when funds have been raised in currencies other than dollars.
The Group's finance debt is almost entirely in US dollars and at December
31, 2002 amounted to $22,008 million (2001 $21,417 million) of which $10,086
million (2001 $9,090 million) was short term.
Net debt, that is debt less cash and liquid resources, was $20,273 million
at the end of 2002, an increase of $664 million over the year. The ratio of net
debt to net debt plus equity was 22% at the end of 2002 and 23% at the end of
2001. After adjusting for the fixed asset revaluation adjustment and goodwill
consequent upon the ARCO and Burmah Castrol acquisitions, the ratio of net debt
to net debt plus equity was 28%. We expect to keep this adjusted ratio in the
range of 25% to 35%.
The maturity profile and fixed/floating rate characteristics of the Group's
debt are described in Item 18 -- Financial Statements -- Notes 26 and 29.
In addition to reported debt, BP uses conventional off balance sheet
arrangements such as operating leases and borrowings in joint ventures and
associated undertakings. At December 31, 2002 the Group's share of third party
borrowings of joint ventures and associated undertakings was $457 million (2001
$460 million) and $849 million (2001 $1,136 million) respectively. These amounts
are not reflected in the Group's debt on the balance sheet.
The Group has issued third party guarantees under which amounts outstanding
at December 31, 2002 are summarized below. Some guarantees outstanding are in
respect of borrowings of joint ventures and associated undertakings noted above.
Guarantees expiring by period
-------------------------------------------------------------
2008 and
Total 2003 2004 2005 2006 2007 thereafter
----- ----- ----- ----- ----- ----- ----------
($ million)
Guarantees issued in respect of:
Borrowings of joint ventures and
associated undertakings.............. 338 -- -- 100 -- 100 138
Liabilities of other third parties..... 293 133 65 9 9 11 66
At December 31, 2002 contracts had been placed for authorized future
capital expenditure estimated at $5,966 million, mainly in respect of
exploration and production activities. Such expenditure is expected to be
financed largely by cash flow from operating activities. The Group also has
access to significant sources of liquidity in the form of committed facilities
and other funding through the capital markets. At December 31, 2002, the Group
had available undrawn committed borrowing facilities of $3,600 million ($3,400
million at December 31, 2001).
On February 11, BP announced the formation of a joint venture with AAR in
Russia. The deal is scheduled for completion in the summer of 2003, at which
time BP will pay AAR approximately $3 billion in cash.
Page 89
The following table summarizes the Group's principal contractual
obligations. Further information on borrowings and capital leases is given in
Item 18 -- Financial Statements -- Note 28 and further information on operating
leases is given in Item 18 -- Financial Statements -- Note 34.
Payments due by period
----------------------------------------------------------------
2008 and
Contractual obligations payments due by period Total 2003 2004 2005 2006 2007 thereafter
----- ----- ----- ----- ----- ----- ----------
($ million)
Long-term borrowings........................... 14,609 4,609 830 2,690 505 1,603 4,372
Finance lease obligations...................... 4,423 106 204 211 218 203 3,481
Operating leases............................... 7,110 1,203 975 859 778 643 2,652
Unconditional purchase obligations............. 13,707 2,896 1,767 1,336 1,093 826 5,789
The following table summarizes the nature of the Group's long-term
unconditional purchase obligations. The Group enters into these arrangements
principally to secure long-term access to supplies of crude oil, natural gas,
feedstocks and pipeline systems.
Payments due by period
-----------------------------------------------------------------
2008 and
Unconditional purchase Total 2003 2004 2005 2006 2007 thereafter
obligations payments due by period ----- ----- ----- ----- ----- ----- ----------
($ million)
Crude oil and oil products................ 2,741 1,239 503 304 226 90 379
Natural gas............................... 2,651 410 354 256 206 159 1,266
Chemicals and other refinery feedstocks... 4,147 320 311 306 302 297 2,611
Utilities................................. 770 119 109 67 55 48 372
Transportation............................ 2,175 626 359 298 202 138 552
Use of facilities and services............ 1,223 182 131 105 102 94 609
------ ----- ----- ----- ----- ----- -----
Total..................................... 13,707 2,896 1,767 1,336 1,093 826 5,789
====== ===== ===== ===== ===== ===== =====
We have in place a European Debt Issuance Programme (DIP) and a US Shelf
Registration under each of which the Group may raise $8 billion and $6 billion
of debt respectively for maturities of one month or longer. At March 19, 2003,
the amount drawn down against the DIP was $2,024 million, and $3,550 million
under the US Shelf Registration.
Commercial paper markets in the USA and Europe are a primary source of
liquidity for the Group. At December 31, 2002 the outstanding commercial paper
amounted to $4,853 million (2001 $4,634 million).
BP believes that, taking into account the substantial amounts of undrawn
borrowing facilities available, the Group has sufficient working capital for
foreseeable requirements.
Page 90
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 from Moody's and Standard & Poor's.
Standard & Poor's placed this rating on CreditWatch, following the announcement
of the transaction to form TNK-BP (see Item 4 - Information on the Company --
General -- Recent Developments). In early March 2003, the Company met with
Standard & Poor's to discuss its debt rating. As of the date of this annual
report, we await the outcome of their review.
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 also has
undrawn committed borrowing facilities to meet currently foreseeable borrowing
requirements. At December 31, 2002, the Group had available undrawn committed
facilities of $3,600 million. These committed facilities, which are mainly with
a number of international banks, expire in 2003. The Group expects to renew the
facilities on an annual basis.
Credit Risk
Credit risk is the potential exposure of the Group to loss in the event of
non-performance by a counterparty. The credit risk arising from the Group's
normal commercial operations is controlled by individual operating units within
guidelines. In addition, as a result of its use of derivatives to manage market
risk, the Group has credit exposures through its dealings in the financial and
specialized oil and natural gas markets. The Group controls the related credit
risk through credit approvals, limits, use of netting arrangements and
monitoring procedures. Counterparty credit validation, independent of the
dealers, is undertaken before contractual commitment.
Page 91
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
UK Generally Accepted Accounting Policies
BP prepares its financial statements in accordance with UK generally
accepted accounting practice (UK GAAP). This requires BP Management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities at the date of the accounts and the reported amounts of revenues and
expenses during the reporting period. Actual outcomes could differ from the
estimates and assumptions used.
The accounts for the year ended December 31, 2002 have been prepared using
accounting policies consistent with those used in the preparation of the 2001
accounts, except for the change in accounting policy for deferred tax described
below.
Segment information for 2001 and 2000 has been restated to reflect the
transfer of the solar, renewables and alternative fuels activities from Other
Businesses and Corporate to Gas and Power on January 1, 2002. At the same time
to reflect this transfer Gas and Power was renamed Gas, Power and Renewables.
The accounting policies and areas that require the most significant
judgments and estimates to be used in the preparation of BP's consolidated
financial statements are in relation to oil and natural gas reserves;
depreciation and amounts provided; impairment; and provisions for deferred
taxation, decommissioning, environmental liabilities, pensions and other
postretirement benefits.
Adoption of New UK Accounting Standard
With effect from January 1, 2002 BP has adopted Financial Reporting
Standard No. 19 'Deferred Tax' (FRS 19). This standard generally requires that
deferred tax should be provided on a full liability basis rather than on a
restricted liability basis as required by Statement of Standard Accounting
Practice No. 15 'Accounting for Deferred Tax' (SSAP15). The adoption of FRS 19
has been treated as a change in accounting policy.
Under FRS 19 deferred tax is recognized in respect of all timing
differences that have originated but not reversed at the balance sheet date
where transactions or events have occurred at that date that will result in an
obligation to pay more, or right to pay less tax in the future. In particular:
-- Provision is made for tax on gains arising from the disposal of fixed
assets that have been rolled over into replacement assets, only to the
extent that, at the balance sheet date, there is a binding agreement
to dispose of the replacement assets concerned. However, no provision
is made where, on the basis of all available evidence at the balance
sheet date, it is more likely than not that the taxable gain will be
rolled over into replacement assets and charged to tax only where the
replacement assets are sold.
-- Provision is made for deferred tax that would arise on remittance of
the retained earnings of overseas subsidiaries, joint ventures and
associated undertakings only to the extent that, at the balance sheet
date, dividends have been accrued as receivable.
Deferred tax assets are recognized only to the extent that it is considered
more likely than not that there will be suitable taxable profits from which the
underlying timing differences can be deducted.
Deferred tax is measured on an undiscounted basis at the tax rates that are
expected to apply in the periods in which timing differences reverse, based on
tax rates and laws enacted or substantively enacted at the balance sheet date.
When an acquisition has been made prior to the date of adopting FRS 19, the
accounting standard requires that the fair values attributed to assets and
liabilities at the date of acquisition be restated as though FRS 19 had applied
at that time. Applying this principle has led to the creation of additional
amounts of deferred taxation and additional amounts of goodwill on acquisitions
made prior to January 1, 2002.
Page 92
The change in accounting policy has resulted in a prior year adjustment.
Shareholders' interest at January 1, 2000 has been reduced by $6,250 million and
the tax charge for the years ended December 31, 2001 and 2000 increased by
$1,358 million and $1,676 million respectively. The provision for deferred tax
has been increased by $10,047 million at December 31, 2001. Profit for the
current year has been reduced by approximately $750 million as a result of the
change in accounting policy.
Oil and Gas Reserves
BP's oil and natural gas reserves are estimated by the Group's petroleum
engineers in accordance with industry standards and SEC regulations. Proved oil
and gas reserves are the estimated quantities of crude oil, NGLs and 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. Accordingly, these estimates do not include probable or
possible reserves. Estimated oil and gas reserves are based on available
reservoir data and prices and costs as of the date the estimate is made and are
subject to future revision.
As discussed below, oil and natural gas reserves have a direct impact on
certain amounts reported in the financial statements.
Depreciation and Amounts Provided
The Group follows the successful efforts method of accounting for its oil
and gas activities. This accounting principle requires, among other things, that
the capitalized costs for proved oil and gas properties (which include the costs
of drilling successful wells) be amortized on the basis of oil-equivalent
barrels that are produced in a period as a percentage of the total estimated
proved reserves. The impact of changes in estimated proved reserves are dealt
with prospectively by amortizing the remaining book value of the asset over the
expected future production. If proved reserve estimates are revised downward,
earnings could be affected by higher depreciation expense or an immediate
write-down of the property's book value (see impairment discussion below).
Given the large number of producing fields in the Group's portfolio, it is
unlikely that any changes in reserve estimates, year on year, will have a
significant effect on prospective charges for depreciation.
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, with most goodwill amortized over 10 years. The 10-year amortization
period chosen for the goodwill arising on the ARCO, Burmah Castrol and Veba
acquisitions reflects the period over which the benefit of cost synergies is
expected to be eroded.
During the period 2000 to 2002 there have been no changes in the estimated
useful lives of the Group's major asset categories. No significant changes are
expected in 2003. The Group believes its asset lives are similar to those of its
major competitors.
Impairment of Fixed Assets and Goodwill
Fixed assets, including goodwill are assessed for impairment if there are
events or changes in circumstances which indicate that carrying values of those
assets may not be recoverable. This entails comparing the carrying value of the
income-generating unit and associated goodwill with the recoverable amount of
the asset, that is, the higher of net realizable value and value in use. Value
in use is usually determined on the basis of discounted estimated future net
cash flows.
Page 93
For oil and natural gas properties, the expected future cash flows are
estimated based on the Group's plans to continue to produce and develop proved
and associated risk-adjusted probable and possible reserves. Expected future
cash flows from the sale or production of reserves are calculated based on a
Brent oil price of $20 and a Henry Hub gas price of $3.20. These represent
10-year historic average prices. The net present values of cash flows are
determined using a discount rate of 9%. The estimated future level of production
is based on assumptions about future commodity prices, lifting and development
costs, field decline rates, market demand and supply, economic regulatory
climates and other factors.
Charges for impairment are recognized in the Group's results from time to
time as a result of, among other factors, adverse changes in the recoverable
reserves from oil and natural gas fields, low plant utilization or reduced
profitability. See Group Operating Results within this item for a discussion of
impairment charges recognized in 2002. If there are low oil prices or natural
gas prices or refining margins or chemicals margins over an extended period, the
Group may need to recognize significant impairment charges.
Deferred Taxation
The Group has approximately $5,300 million of carry-forward tax losses in
the UK, which are available to offset against future taxable income. To date,
tax assets have been recognized on $840 million of those losses (i.e., to the
extent that it is regarded as more likely than not that suitable taxable income
will arise). It is unlikely that the Group's effective tax rate will be
significantly affected in the near term by utilisation of losses not previously
recognized as deferred tax assets. Carry-forward tax losses in other taxing
jurisdictions have not been recognized as deferred tax assets, and are not
likely to have a significant effect on the Group's tax rate in the near term.
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 associated undertakings.
Decommissioning Costs
The Group holds provisions for the future decommissioning of oil and
natural gas production facilities and pipelines at the end of their economic
lives. The largest asset removal obligations facing BP relate to the removal and
disposal of oil and natural gas platforms and pipelines around the world. The
estimated discounted costs of dismantling and removing these facilities are
accrued at the commencement of production, reflecting our legal obligations.
Most of these removal events are many years in the future and the precise
requirements that will have to be met when the removal event actually occurs are
uncertain. Asset removal technologies and costs are constantly changing, as well
as political, environmental, safety and public expectations. Consequently, the
timing and amounts of future cash flows are subject to significant uncertainty.
The timing and amount of future expenditures are reviewed annually together
with the interest rate to be used in discounting the cash flows. The interest
rate used to determine the balance sheet obligation at year end 2002 was 2.5%
down from 3.0% at the end of 2001. This change in the discount rate increased
the provision for decommissioning costs by $334 million at December 31, 2002.
Environmental Costs
BP also makes judgments and estimates in recording costs and establishing
provisions for environmental clean-up and remediation costs, which are based on
current information on costs and expected plans for remediation. For
environmental provisions, actual costs can differ from estimates because of
changes in laws and regulations, public expectations, discovery and analysis of
site conditions and changes in clean-up technology.
The provision for environmental liabilities is reviewed annually. The
change in the discount rate, from 3.0% at year end 2001 to 2.5% at year end
2002, increased the provision for environmental liabilities by $36 million at
end 2002.
Page 94
Pensions and Other Postretirement Benefits
Accounting for pensions and other postretirement benefits involves judgment
about uncertain events, including estimated retirement dates, salary levels at
retirement, mortality rates, rates of return on plan assets, determination of
discount rates for measuring plan obligations, health care cost-trend rates and
rates of utilization of health care services by retirees. These assumptions are
based on the environment in each country. Determination of the projected benefit
obligations for the Company's defined benefit pension and postretirement plans
are important to the recorded amounts for such obligations on the balance sheet
and to the amount of benefit expense in the income statement. The assumptions
used may vary from year-to-year, which will affect future results of operations.
Any differences between these assumptions and the actual outcome also impacts
future results of operations.
Pension and other postretirement benefit assumptions are discussed and
agreed with the independent actuaries in December each year. These assumptions
are used to determine the projected benefit obligation at the year end and hence
the liability or asset recorded on the Group's balance sheet, and pension
expense for the following year.
The pension assumptions at December 31, 2002 and 2001 under Statement of
Standard Accounting Practice No. 24 'Accounting for Pension Costs' (SSAP 24) are
summarized below. The change in assumptions should lead to a net increase in
pension expense in 2003 of approximately $300 million.
UK Other European USA
------------------- ------------------- -------------------
2002 2001 2002 2001 2002 2001
------- ------- ------- ------- ------- -------
(%)
Rate of return on assets............ 6.25 6.0 n/a n/a 8.0 10.0
Discount rate....................... 6.25 6.0 5.75 6.2 6.75 7.25
Future salary increases............. 4.0 4.5 4.0 3.2 4.0 4.0
Future pension increases............ 2.5 2.5 2.4 2.0 -- --
Dividend growth..................... n/a n/a n/a n/a n/a n/a
The assumed rate of investment return and discount rate have a significant
effect on the amounts reported. A one-percentage-point change in these
assumptions for the principal plans would have the following effects:
One percentage point
---------------------
Increase Decrease
-------- --------
($ million)
Investment return:
Effect on pension expense in 2002..................................... (240) 240
Discount rate:
Effect on pension expense in 2002..................................... (320) 275
Effect on pension obligation at December 31, 2002..................... (3,575) 3,625
The assumptions used in calculating the charge for US postretirement
benefits are consistent with those shown above for US pension plans. The assumed
future healthcare cost trend rate is shown below.
2009 and
subsequent
2003 2004 2005 2006 2007 2008 years
----- ----- ----- ----- ----- ----- ----------
(%)
Beneficiaries aged under 65............... 12 11 9 8 7 6 5
Beneficiaries aged over 65................ 15 14 12 10 8 7 6
The change in assumptions between 2002 and 2003 should result in an
increase in postretirement benefits of approximately $140 million.
Page 95
The assumed healthcare cost trend rate has a significant effect on the
amounts reported. A one-percentage-point change in the assumed healthcare cost
trend rate would have the following effects:
One percentage point
---------------------
Increase Decrease
-------- --------
($ million)
Effect on total of service and interest cost in 2002........................... 52 (41)
Effect on postretirement obligation at December 31, in 2002................... 587 (476)
Under SSAP 24 surpluses and deficits on pension and other postretirement
benefit plans are not recognized immediately, but spread over a number of years.
On the basis of SSAP 24 the asset or liability reflected in the Group's balance
sheet at December 31, 2002 for the major pension and postretirement benefit
plans, net of tax, is as follows:
USA
Other ------------------------
UK European Postretirement
Pension Pension Pension benefits
---------- ---------- ---------- -----------
($ million)
Asset (liability)........................... 1,882 (2,883) 787 (1,795)
If the assets and liabilities of the pension and postretirement benefits
plans were measured at fair value at December 31, 2002 in accordance with
Financial Reporting Standard No. 17, the assets and liabilities that would be
recognized in the Group's balance sheet are set out below. The aggregate impact
of using this basis would be to reduce BP Shareholders' interest by
approximately $4.2 billion.
USA
Other ------------------------
UK European Postretirement
Pension Pension Pension benefits
---------- ---------- ---------- -----------
($ million)
Asset (liability)........................... 221 (1,947) (1,663) (2,790)
The Other European pension plans and US postretirement benefit plans are
unfunded; payments to beneficiaries are made by the Group from its operating
cash flows and other resources. The UK and US pension plans are generally
funded. Subject to finalization of the actuarial valuation it is expected that a
contribution in the range of $500 million to $700 million will be made to the US
pension plan in 2003.
Page 96
Impact of New UK Accounting Standards
Retirement benefits: In December 2000, the UK Accounting Standards Board
issued Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17). This
standard was to be fully effective for accounting periods ending on or after
June 22, 2003 with certain of the disclosure requirements effective for periods
prior to 2003. However, in November 2002, the UK Accounting Standards Board
issued an amendment to FRS 17, which defers full adoption until January 1, 2005
although the disclosure requirements apply to periods prior to 2005. FRS 17
requires that financial statements reflect at fair value the assets and
liabilities arising from an employer's retirement benefit obligations and any
related funding. The operating costs of providing retirement benefits are
recognized in the period in which they are earned together with any related
finance costs and changes in the value of related assets and liabilities.
The pro forma impact of adopting this standard on pensions and
postretirement benefits is shown in Notes 40 and 41 of Notes to Financial
Statements.
US Generally Accepted Accounting Principles
The consolidated financial statements of the BP Group are prepared in
accordance with UK GAAP which differs in certain respects from US generally
accepted accounting principles (US GAAP). The principal differences between US
GAAP and UK GAAP for BP Group reporting are discussed in Note 45 of Notes to
Financial Statements.
Impact of New US Accounting Standards
New US accounting standards adopted: The Group has adopted Statement of
Financial Accounting Standards No. 141 'Business Combinations' (SFAS 141) for US
GAAP reporting with effect from January 1, 2002. Under SFAS 141, the pooling of
interest method of accounting is no longer permitted. Also on January 1, 2002
the Group adopted Statement of Financial Accounting Standards No. 144
'Accounting for the Impairment or Disposal of Long-Lived Assets' (SFAS 144).
SFAS 144 retains the requirement to recognize an impairment loss only where the
carrying value of a long-lived asset is not recoverable from its undiscounted
cash flows and to measure such loss as the difference between the carrying
amount and fair value of the asset. SFAS 144, among other things, changes the
criteria that have to be met in order to classify an asset as held-for-sale and
requires that operating losses from discontinued operations be recognized in the
period that the losses are incurred rather than as of the measurement date.
The adoption of SFAS 141 and SFAS 144 had no impact on profit, as adjusted
to accord with US GAAP, for the year ended December 31, 2002 or on BP
shareholders' interest, as adjusted to accord with US GAAP, at December 31,
2002.
Asset retirement obligations: In June 2001, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting Standards No.
143 'Accounting for Asset Retirement Obligations' (SFAS 143). SFAS 143 requires
companies to record liabilities equal to the fair value of their asset
retirement obligations when they are incurred (typically when the asset is
installed at the production location). When the liability is initially recorded,
companies capitalize an equivalent amount as part of the cost of the asset. Over
time the liability is accreted for the change in its present value each period,
and the initial capitalized cost is depreciated over the useful life of the
related asset. SFAS 143 is effective for accounting periods beginning after June
15, 2002.
The cumulative effect of adopting SFAS 143 at January 1, 2003 will result
in an after tax credit to income, as adjusted to accord with US GAAP, of
approximately $1,700 million. The effect of adoption also included an increase
in total assets, as adjusted to accord with US GAAP, of approximately $660
million and a reduction in total liabilities, as adjusted to accord with US
GAAP, of approximately $1,040 million. It is expected that there will be an
additional charge to profit, adjusted to accord with US GAAP, in the range of
$200 to 250 million in future periods.
Page 97
Costs associated with exit or disposal activities: In June 2002, the FASB
issued Statement of Financial Accounting Standards No. 146 'Accounting for Costs
Associated with Exit or Disposal Activities' (SFAS 146). SFAS 146 requires that
a liability for costs associated with an exit or disposal activity be recognized
only when the liability is incurred, rather than at the date of an entity's
commitment to an exit plan. The new standard requires that the liability be
initially measured at fair value. SFAS 146 is effective for exit or disposal
activities that are initiated after December 31, 2002.
Contracts involved in energy trading activities: In October 2002, the FASB
Emerging Issues Task Force (EITF) reached a consensus which rescinded EITF Issue
No. 98-10, 'Accounting for Contracts Involved in Energy Trading and Risk
Management Activities' (EITF 98-10). As a result of this consensus, all
energy-related, non-derivative contracts (such as transportation, storage,
tolling, and requirements contracts that do not meet the definition of a
derivative) and trading inventories that are accounted for at fair value
pursuant to EITF 98-10 will no longer be accounted for at fair value upon
application of the consensus. Rather, such contracts will be accounted for as
executory contacts on an accruals basis.
The consensus is applicable for all contracts executed after October 25,
2002. Application of the consensus to contracts existing prior to October 26,
2002 is required to be accounted for as a cumulative effect of a change in
accounting principle effective for periods beginning after December 15, 2002.
For BP's reporting under UK GAAP, energy-related non-derivative contracts
associated with trading activities are marked to market with gains and losses
recognized in the income statement.
The cumulative effect of adopting the consensus at January 1, 2003 will
result in an after tax credit to income, as adjusted to accord with US GAAP, of
approximately $50 million.
Stock-based compensation: In December 2002, the FASB issued Statement of
Financial Accounting Standards No. 148 'Accounting for Stock-Based Compensation
- Transition and Disclosure' (SFAS 148). SFAS 148 amends SFAS 123 to permit
alternative methods of transition for adopting a fair value based method of
accounting for stock-based employee compensation. Under UK GAAP, the Group uses
the intrinsic value method to account for stock-based employee compensation.
Guarantees: In November 2002, the FASB issued FASB Interpretation No. 45
'Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others' (Interpretation 45).
Interpretation 45 elaborates on existing disclosure requirements for guarantees
and clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and measurement provisions of
Interpretation 45 apply on a prospective basis to guarantees issued or modified
after December 31, 2002.
Consolidation: In January 2003, the FASB issued FASB Interpretation No. 46
'Consolidation of Variable Interest Entities' (Interpretation 46).
Interpretation 46 clarifies the application of existing consolidation
requirements to entities where a controlling financial interest is achieved
through arrangements that do not involve voting interests. Under Interpretation
46, a variable interest entity is consolidated if a company is subject to a
majority of the risk of loss from the variable interest entity's activities or
entitled to receive a majority of the entity's residual returns. Interpretation
46 applies to variable interest entities created or acquired after January 31,
2003. For variable interest entities existing at January 31, 2003,
Interpretation 46 is effective for accounting periods beginning after June 15,
2003.
The Company is currently carrying out the analysis necessary to adopt
Interpretation 46 in the third quarter of 2003 for existing entities. The
Company does not expect that the adoption of Interpretation 46 will have a
significant effect on profit as adjusted to accord with US GAAP, or BP
shareholders' interest, as adjusted to accord with US GAAP.
Page 98
Impact of International Accounting Standards
In June 2002, the European Union Council of Ministers adopted a Regulation
which will require the Group to prepare its primary consolidated financial
statements in accordance with International Accounting Standards (IAS) beginning
January 1, 2005, with restatement of prior periods presented. IAS differ in
several respects from UK and US GAAP. In addition, significant revisions to IAS
are currently being contemplated and other revisions may be adopted prior to
January 1, 2005. The Group has not determined the effects of adopting IAS.
Page 99
ITEM 6 -- DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
DIRECTORS AND SENIOR MANAGEMENT
The following lists the Company's directors and senior management.
Initially elected
Name or appointed
------ --------------
P D Sutherland....................... Non-executive chairman (a) Chairman since May 1997
Director since July 1995
Sir Ian Prosser...................... Non-executive deputy chairman (a)(b)(c) Deputy chairman since
February 1999
Director since May 1997
The Lord Browne of Madingley......... Executive director (Group chief September 1991
executive)
R C Alexander........................ Chief executive, Gas, Power
and Renewables April 2002
Dr D C Allen......................... Executive director February 2003
P B P Bevan.......................... Group general counsel September 1992
R F Chase............................ Executive director March 1992
I C Conn............................. Chief executive, Chemicals November 2002
Dr A B Hayward....................... Executive director February 2003
J A Manzoni.......................... Executive director February 2003
Dr B E Grote......................... Executive director (Chief financial
officer) August 2000
R L Olver............................ Executive director (Deputy group
chief executive) January 1998
J H Bryan............................ Non-executive director (a)(c) December 1998
E B Davis, Jr........................ Non-executive director (a)(b)(c) December 1998
Dr D S Julius........................ Non-executive director (a)(b) November 2001
C F Knight........................... Non-executive director (a)(b) October 1987
F A Maljers.......................... Non-executive director (a)(d) December 1998
Dr W E Massey........................ Non-executive director (a)(d) December 1998
H M P Miles.......................... Non-executive director (a)(c)(d) June 1994
Sir Robin Nicholson.................. Non-executive director (a)(b) October 1987
M H Wilson........................... Non-executive director (a)(c)(d) December 1998
----------
(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 W D Ford retired as an executive director on March 31, 2002. Sir Robert
Wilson retired as a non-executive director on April 18, 2002. Dr J G S Buchanan
retired as an executive director and chief financial officer on November 21,
2002. Mr R F Chase will retire as an executive director on April 23, 2003. BP's
articles of association require directors who have held office for three years
or more since they were appointed or re-elected to retire from office at the
Company's annual general meeting, together with directors appointed by the board
since the last annual general meeting. Retiring directors may offer themselves
for re-election. The Director retiring and offering himself for re-election at
this year's meeting is Mr C F Knight. Dr D C Allen, Dr A B Hayward and Mr J A
Manzoni are standing for election by the shareholders.
Page 100
The biographies of the directors and the secretary are set out below.
P D Sutherland, SC -- Peter Sutherland (56) rejoined BP's board in 1995,
having previously been a non-executive director from 1990 to 1993. He was
appointed chairman of BP in 1997. He is non-executive chairman of Goldman Sachs
International and a non-executive director of Telefonaktiebolaget LM Ericsson,
Investor AB and The Royal Bank of Scotland Group.
Sir Ian Prosser -- Sir Ian (59) joined BP's board in 1997 and was appointed
non-executive deputy chairman in 1999. He is chairman of Six Continents. He is
also a non-executive director of GlaxoSmithKline, and chairman of the Executive
Committee of the World Travel and Tourism Council.
The Lord Browne of Madingley, FREng -- Lord Browne, formerly Sir John
Browne, (55), group chief executive, 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, and a trustee of the British Museum.
R C Alexander - Ralph Alexander (47), was appointed chief executive of Gas,
Power and Renewables in April 2002.
Dr D C Allen -- David Allen (48), group chief of staff, was appointed an
executive director of BP in February 2003.
P B P Bevan - Peter Bevan (58), was appointed group general counsel in
1992.
R F Chase -- Rodney Chase (59), senior adviser to the group chief
executive, was appointed an executive director of BP in 1992. He is a
non-executive director of Computer Sciences Corporation, Diageo and Tesco. He is
also a trustee of the Prince of Wales International Business Leaders Forum and a
member of the Executive Board of the World Council for Sustainable Development.
I C Conn - Iain Conn (40), was appointed chief executive of Chemicals in
November 2002.
Dr B E Grote -- Byron Grote (54), chief financial officer, was appointed an
executive director of BP in 2000 and chief financial officer in November 2002.
Dr A B Hayward -- Tony Hayward (45), chief executive, Exploration and
Production, was appointed an executive director of BP in February 2003. He is a
non-executive director of Corus Group.
J A Manzoni -- John Manzoni (43), chief executive, Refining and Marketing,
was appointed an executive director of BP in February 2003.
R L Olver -- Dick Olver (56), deputy group chief executive, was appointed
an executive director of BP in 1998, and deputy group chief executive in January
2003. He is a non-executive director of Reuters Group.
J H Bryan -- John Bryan (66) joined Amoco's board in 1982. He serves on the
boards of Bank One Corporation, General Motors Corporation and Goldman Sachs. He
retired as chairman of Sara Lee Corporation in 2001.
E B Davis, Jr -- Erroll B Davis, Jr (58) 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. He serves as a director of the Wisconsin Association of
Manufacturers and Commerce, the Edison Electric Institute and the Electric Power
Research Institute. He is also chairman of the board of trustees of Carnegie
Mellon University.
Dr D S Julius, CBE -- DeAnne Julius (53) joined BP's board in November
2001. She is a non-executive director of the Court of the Bank of England,
Lloyds TSB, Serco and Roche Holding. From 1997 until June 2001 she was a full
time member of the Monetary Policy Committee of the Bank of England.
C F Knight -- Charles Knight (67) joined BP's board in 1987. He is chairman
of Emerson Electric and is a non-executive director of Anheuser-Busch, Morgan
Stanley Dean Witter, SBC Communications and IBM.
Page 101
F A Maljers, KBE -- Floris Maljers (69) joined Amoco's board in 1994. He is
a member of the supervisory boards of SHV Holding and Vendex NV. He is chairman
of the supervisory boards of KLM Royal Dutch Airlines, the Amsterdam
Concertgebouw NV and Rotterdam School of Management, Erasmus University.
Dr W E Massey -- Walter Massey (64) 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. He serves on
President Bush's Council of Advisors on Science and Technology.
H M P Miles, OBE -- Michael Miles (66) joined BP's board in 1994. He is
chairman of Schroders and of Johnson Matthey.
Sir Robin Nicholson, FREng, FRS -- Sir Robin (68) joined BP's board in
1987. He is a non-executive director of Rolls-Royce.
M H Wilson -- Michael Wilson (65) joined Amoco's board in 1993. He is
president and chief executive officer of UBS Global Asset Management (Canada)
and a non-executive director of Manufacturers Life Insurance Company and UBS
Global Asset Management.
Page 102
COMPENSATION
The remuneration committee determines the terms of engagement and
remuneration of the executive directors.
Reward Policy
The remuneration committee's reward policy reflects its obligation to align
executive directors' remuneration with shareholders' interests and to engage
world-class executive talent for the benefit of the Group. The main principles
of the policy are:
-- Total rewards should be set at appropriate levels to reflect the
competitive global market in which BP operates.
-- The majority of the total reward should be linked to the achievement
of demanding performance targets.
-- Executive directors' incentives should be aligned with the interests
of ordinary shareholders. This is achieved through setting performance
targets that are based on measures of shareholders' interests and
through the committee's policy that each executive director should
hold a significant shareholding in the Company, currently equivalent
to 5 x the director's base salary.
-- The performance targets in the Executive Directors' Incentive Plan
(EDIP) should encompass demanding comparisons of BP's shareholder
returns and earnings with those of other companies in its own industry
and in the broader marketplace.
-- The wider scene, including pay and employment conditions elsewhere in
the Group, should be taken into account, especially when determining
annual salary increases.
Elements of Remuneration
The executive directors' total remuneration consists of salary, annual
bonus, long-term incentives, pensions and other benefits. This reward structure
is regularly reviewed by the committee to ensure that it is achieving its
objectives. In 2003, over three-quarters of executive directors' potential
direct remuneration will again be performance related. It is intended that this
balance of elements should continue.
Salary
Each executive director receives a fixed sum payable monthly in cash. The
committee expects to review salaries later in 2003 in line with global markets.
The appropriate survey groups are defined and analyzed by external remuneration
advisers.
Annual Bonus
Each executive director is eligible to participate in an annual
performance-based bonus scheme. The remuneration committee reviews and sets
bonus targets and levels of eligibility annually. The target level is 100% of
base salary (except for Lord Browne, for whom, as group chief executive, it is
considered appropriate to have a target of 110%). There is a stretch level of
150% of base salary for substantially exceeding targets. Executive directors'
annual bonus awards for 2003 will again be based on a mix of demanding financial
targets and other leadership objectives, established at the beginning of the
year. In addition to business performance, they cover areas such as people,
safety, environment and organization.
Page 103
Long-term Incentives
Long-term incentives are provided under the EDIP, which was approved by
shareholders in April 2000. It has three elements: a share element, a share
option element and a cash element. Each executive director participates in this
plan. The committee's policy, subject to unforeseen circumstances, is that this
should continue until the plan expires or is renewed in 2005. The committee's
policy for 2003 is to continue to use only the share element and the share
option element. The committee's policy that each executive director should hold
shares equivalent to 5 x the director's base salary is reflected in the terms of
the plan.
The performance conditions in the share element and share option elements
of the EDIP were selected to ensure that executive directors' long-term
remuneration under the EDIP is appropriately balanced between elements testing
BP's performance against that of competitors in the oil industry and elements
testing BP's performance against that of the leading global companies.
Share Element
The share element permits the remuneration committee to grant `performance
units' to executive directors, which may result in an award of shares (without
payment by the directors) at the end of a three-year performance period if
demanding performance conditions are met. The maximum number of shares that may
be awarded for each performance unit is two.
Shares awarded are then held in trust for three years before they are
released to the individual. This gives the executive directors a six-year
incentive structure, and ensures their interests are aligned with those of
shareholders.
The share element compares BP's performance against the oil and gas sector
over three years on a rolling basis. This is assessed in terms of a three year
total shareholder return against the market (SHRAM), return on average capital
employed (ROACE) and earnings per share growth, based on pro forma results
adjusted for special items (EPS). SHRAM is the primary measure, accounting for
nearly two-thirds of the potential total award. All calculations are reviewed by
the external auditors to ensure that they meet an independent objective
standard. The relative position of the Company within the comparator group
determines the number of shares awarded per performance unit.
For the 2001-2003 plan, BP's three-year SHRAM is measured against the other
oil majors: ExxonMobil, Shell, TotalFinaElf and ChevronTexaco. Due to the
reduced number of oil majors, for the 2002-2004 and 2003-2005 plans BP's
three-year SHRAM is measured against the companies in the FTSE All World Oil and
Gas Index. Companies within the index are weighted according to their market
capitalization at the beginning of each three-year period in order to give
greatest emphasis to oil majors.
The committee reviews and approves annually the performance measures and
the comparator companies. The policy for 2003 and for the foreseeable future is
to continue with the SHRAM measure adopted by the committee in relation to the
2002-2004 and 2003-2005 plans.
BP's ROACE and EPS for all the plans since April 2001 are, and for the
foreseeable future will be, measured against ExxonMobil, Shell, TotalFinaElf and
ChevronTexaco.
Page 104
Share Option Element
The share option element of the EDIP is designed to reflect BP's
performance relative to a wider selection of global companies. It has a
disclosed three-year pre-grant performance requirement that differentiates it
from traditional share option schemes. Under this element, options may be
granted to executive directors at an exercise price no lower than the market
value (as determined in accordance with the plan rules) of a share at the date
the option is granted. Reflecting the pre-grant performance requirement, options
vest over three years after grant (one-third each after one, two and three years
respectively). They have a life of seven years after grant.
In accordance with the framework approved by shareholders in 2000, it is
the committee's policy to continue exercising its judgement to decide the number
of options to be granted to each executive director, taking into account BP's
total shareholder return (TSR) compared with the TSR for the FTSE Global 100
group of companies over the three years preceding the grant. The committee will
not grant options in any year unless the criteria for an award of shares under
the share element have been met. These methods of calculation were chosen to
enable the committee to take into account not only the TSR position but also the
underlying health of the business and the competitive marketplace.
Following grant, the options are not subject to any performance conditions.
The remuneration committee favours this approach for two main reasons. First, it
has the effect of treating share options as a reward both for past performance
(because BP's ranking within a comparator group will have been taken into
account in determining the number of shares under option) and as an incentive
for future performance (because the participant's gain under the option will
depend on share price growth after the grant under the option). Second, BP
operates internationally and the application of a performance condition after
grant is not a feature of option schemes operated by major international
companies based outside the UK.
Cash Element
The cash element allows the remuneration committee to grant cash rather
than share-based incentives in exceptional circumstances. This element was not
used in 2002, and the committee has no present intention to use it in 2003.
Other Benefits
Pension
Executive directors are eligible to participate in the appropriate pension
schemes applicable in their home countries.
Benefits and Other Share Schemes
Executive directors are eligible to participate in regular employee benefit
plans and in all-employee share schemes and savings plans as applicable in their
home countries. Benefits in kind are not pensionable.
Resettlement Allowance
Expatriates may receive a resettlement allowance for a limited period.
Page 105
New Appointees
Dr Allen, Dr Hayward and Mr Manzoni were appointed executive directors on
February 1, 2003, each on a base salary of (pound)400,000 per annum. They are
subject to the committee's policy on executive directors' remuneration, as
described above. As such, they will be eligible to participate in the annual
bonus scheme and EDIP described above on a similar basis to the other executive
directors.
2002 Remuneration for Executive Directors
The table below represents remuneration received by executive directors in
the 2002 financial year, with the exception of the 2002 annual bonus which was
earned in 2002 but paid in 2003. Amounts are shown in both US dollars and pounds
sterling and are converted at the rate of (pound)1 = $1.44 for 2001 and (pound)1
= $1.50 for 2002. Lord Browne, Mr Chase, Mr Olver and Dr Buchanan received their
remuneration in pounds sterling; Dr Grote and Mr Ford in US dollars.
Annual remuneration Long term Performance Plan (LTPP) Grants under EDIP
---------------------------------------- ---------------------------------- ------------------------
2000-2002 LTPP 1999-2001 LTPP 2002-2004 Share
(awarded in (awarded in Share option
Feb 2003) Feb 2002) element element
2002 annual (granted in Feb 2002)
performance Other 2002 2001 Actual Actual
Salary bonus benefits total total award Value award Value(c) (performance
Summary of 2002 `000 `000 `000 `000 `000 (shares)(a) `000(b)(shares) `000 units)(d) (options)(e)
Remuneration ------ ----- -------- ----- ----- ------ ----- ------ ------ ------------ --------
($) ($) ($) ($) ($) ($) ($)
(pounds) (pounds)(pounds) (pounds) (pounds) (pounds) (pounds)
The Lord Browne
of Madingley..... $1,926 $2,543 $78 $4,547 $4,373 224,000 $1,329 472,500 $3,875 475,556 1,348,032
.................... 1,284 1,695 52 3,031 3,037 886 2,691
R F Chase.......... $960 $1,152 $47 $2,159 $2,042 139,200 $826 315,000 $2,583 272,031 --
.................... 640 768 32 1,440 1,418 551 1,794
Dr B E Grote....... $713 $856 $302(f) $1,871 $1,864 68,000 $403 175,000 $1,436 182,613 349,038
.................... 475 570 202 1,247 1,294 269 997
R L Olver.......... $795 $954 $56 $1,805 $1,717 117,600 $698 252,000 $2,066 196,296 370,956
.................... 530 636 37 1,203 1,192 465 1,435
Directors leaving the board in 2002 (g)
Dr J G S Buchanan.. $715 $787 $26 $1,528 $1,656 123,200 $731 280,000 $2,297 221,026 --
.................... 477 524 17 1,018 1,150 487 1,595
W D Ford........... $180 $180 $148(f) $508 $2,188 105,600 $626 175,000 $1,436 -- --
.................... 120 120 99 339 1,519 418 997
------------
(a) Gross award of shares based on a performance assessment by the remuneration
committee and on the other terms of the plan. Sufficient shares are sold to
pay for tax applicable. Remaining shares are held in trust until 2006 when
they are released to the individual.
(b) Based on the closing mid-market price of BP shares on February 17, 2003
((pound)3.955/$5.93 at (pound)1=$1.50).
(c) Based on the closing mid-market price on date of award ((pound)5.695/$8.20
at (pound)1=$1.44).
(d) Performance units granted under the 2002-2004 share element of the EDIP are
converted to shares at the end of the performance period. Maximum of two
shares per performance unit.
(e) Options granted in February 2002 have a grant price of (pound)5.715 per
share. Dr Grote holds options over ADSs; the above numbers and prices
reflect calculated equivalents.
(f) Includes resettlement allowances for Dr Grote and Mr Ford of $300,000 and
$110,000 respectively.
(g) Amounts for Dr Buchanan and Mr Ford reflect the eleven months and three
months respectively that they were directors in 2002.
Page 106
Salary
In January 2002 base salaries for executive directors were increased by
less than 10% per annum. Base salaries have recently been increased by 5% per
annum both for Dr Grote on his promotion to chief financial officer and for Mr
Olver on his promotion to deputy group chief executive.
Annual Bonus
The annual bonus awards for 2002 were based on a mix of financial targets
and leadership objectives established at the beginning of the year. Assessment
of all the targets resulted in a target performance of 120 points out of a
maximum of 150, which is some 11% lower than the 135 points last year. The
resulting bonus awards are shown in the summary table above. All calculations in
relation to the annual bonus have been reviewed by the external auditors.
Long-term Performance-based Components
Long Term Performance Plan (LTPP) and Share Element of EDIP
Under the Long Term Performance Plans and the share element of the EDIP,
performance units are granted at the beginning of the period and converted into
an award of shares at the end of the three-year period, depending on
performance. There is a maximum of two shares per performance unit.
Since the adoption of the EDIP in April 2000, the executive directors have
ceased to be eligible for grants under the BP share option plan and the LTPPs.
However, they were not required to relinquish rights under those plans that had
already been granted prior to April 2000 (including performance units under the
LTPPs that have yet to mature into share awards).
The last of these LTPP rights under the 1999-2001 and 2000-2002 plans
matured or mature into share awards in February 2002 and 2003 respectively.
For the 2000-2002 LTPP, BP's performance was assessed in terms of SHRAM,
ROACE and EPS growth - each relative to that of ExxonMobil, Shell, TotalFinaElf,
ChevronTexaco, ENI and Repsol-YPF.
BP's SHRAM came in at sixth place among the comparator group, fourth place
on EPS growth and first place on ROACE.
Based on a performance assessment of 80 points out of 200, the remuneration
committee has made awards of shares to executive directors as highlighted in the
2000-2002 lines of the table on the page following.
Page 107
The following table summarizes the LTPPs and share elements of the
executive directors' remuneration for 2002.
LTPP/Share element interests Interests vested
------------------------------------------------------------------ -----------------------------------
Market
price of Market
each share price of
at date of Number each share
Date of grant of Performance units(b) of at share
grant of performance -------------------------- ordinary award
Performance performance units At Jan 1 Granted At Dec shares Share award date
period(a) units (pound) 2002 2002 31 2002 awarded(c) date (pound)
----------- ----------- ----------- ------- ------- ------- -------- ----------- -------
The Lord Browne 1999-2001 Mar 11, 1999 5.11 270,000 -- -- 472,500 Feb 19, 2002 5.70
of Madingley 2000-2002 Feb 23, 2000 4.59 280,000 -- 280,000 224,000 Feb 17, 2003 3.96
2001-2003 Feb 19, 2001 5.80 415,000 -- 415,000 -- -- --
2002-2004 Feb 18, 2002 5.73 -- 475,556 475,556 -- -- --
R F Chase 1999-2001 Mar 11, 1999 5.11 180,000 -- -- 315,000 Feb 19, 2002 5.70
2000-2002 Feb 23, 2000 4.59 174,000 -- 174,000 139,200 Feb 17, 2003 3.96
2001-2003 Feb 19, 2001 5.80 205,000 -- 205,000 -- -- --
2002-2004 Feb 18, 2002 5.73 -- 237,037 237,037 -- -- --
2002-2004 Mar 13, 2002 6.17 -- 34,994 34,994 -- -- --
Dr B E Grote 1999-2001 Mar 11, 1999 5.11 100,000 -- -- 175,000 Feb 19, 2002 5.70
2000-2002 Feb 23, 2000 4.59 85,000 -- 85,000 68,000 Feb 17, 2003 3.96
2001-2003 Feb 19, 2001 5.80 155,000 -- 155,000 -- -- --
2002-2004 Feb 18, 2002 5.73 -- 182,613 182,613 -- -- --
R L Olver 1999-2001 Mar 11, 1999 5.11 144,000 -- -- 252,000 Feb 19, 2002 5.70
2000-2002 Feb 23, 2000 4.59 147,000 -- 147,000 117,600 Feb 17, 2003 3.96
2001-2003 Feb 19, 2001 5.80 170,000 -- 170,000 -- -- --
2002-2004 Feb 18, 2002 5.73 -- 196,296 196,296 -- -- --
Directors leaving the board in 2002
Dr J G S Buchanan 1998-2000 Feb 5, 1998 4.05 159,900(d) -- -- -- -- --
1999-2001 Mar 11, 1999 5.11 160,000 -- -- 280,000 Feb 19, 2002 5.70
2000-2002 Feb 23, 2000 4.59 154,000 -- 154,000(e) 123,200 Feb 17, 2003 3.96
2001-2003 Feb 19, 2001 5.80 165,000 -- 165,000(e) -- -- --
2002-2004 Feb 18, 2002 5.73 -- 192,593 192,593(e) -- -- --
2002-2004 Mar 13, 2002 6.17 -- 28,433 28,433(e) -- -- --
W D Ford 1999-2001 Mar 11, 1999 5.11 100,000 -- -- 175,000 Feb 19, 2002 5.70
2000-2002 Feb 23, 2000 4.59 132,000 -- 132,000(f) 105,600 Feb 17, 2003 3.96
2001-2003 Feb 19, 2001 5.80 170,000 -- 170,000(f) -- -- --
Former Director
Dr C S Gibson-Smith 1999-2001 Mar 11, 1999 5.11 144,000 -- -- 252,000 Feb 19, 2002 5.70
2000-2002 Feb 23, 2000 4.59 140,000 -- 140,000 112,000 Feb 17, 2003 3.96
---------------
(a) For performance periods up to 2000-2002, performance units were granted
under the LTPPs. Thereafter they were granted under the EDIP as explained
in this item. Each performance period ends on December 31 of the third
year.
(b) Represents number of performance units, each having a maxiumum potential of
two shares depending on performance.
(c) Represents awards of shares or share equivalents made at the end of the
relevant performance period based on performance achieved under rules of
the plan. BP's performance is assessed in terms of three-year SHRAM against
the oil majors. For 1998-2000 this included ExxonMobil, Shell,
TotalFinaElf, ChevronTexaco; for 1999-2001 this included ExxonMobil, Shell,
TotalFinaElf, ChevronTexaco; and for 2000-2002 this included ExxonMobil,
Shell, TotalFinaElf, ChevronTexaco, ENI Repsol-YPF. For the two latter
plans, performance was also assessed in terms of ROACE and EPS growth
against he same oil majors. Dr Grote and Mr Ford received their awards in
ADSs.
(d) Dr Buchanan elected to defer to 2004 the determination of whether an award
should be made for this period.
(e) On leaving the board of BP p.l.c. on November 21, 2002.
(f) On leaving the board of BP p.l.c. on March 31, 2002
Page 108
Share Options
The table below represents the interests of executive directors in options
over Ordinary Shares during 2002.
Market price Date from
Option At At Option at date which first
type Jan 1, 2002 Granted Exercised Dec 31, 2002 price of exercise exercisable Expiry date
------ ----------- --------- --------- ------------ ---------- ------------ ----------- -----------
The Lord Browne
of Madingley SAYE 5,968 -- 5,968 -- (pound)2.89 (pound)4.52 Sept 1, 02 Feb 28, 03
SAYE -- 3,661 -- 3,661 (pound)4.52 -- Sept 1, 07 Feb 28, 08
EDIP 408,522 -- -- 408,522 (pound)5.99 -- May 15, 01 May 15, 07
EDIP 1,269,843 -- -- 1,269,843 (pound)5.67 -- Feb 19, 02 Feb 19, 08
EDIP -- 1,348,032 -- 1,348,032 (pound)5.72 -- Feb 18, 03 Feb 18, 09
R F Chase SAYE 3,388 -- -- 3,388 (pound)4.98 -- Sept 1, 05 Feb 28, 06
EDIP 85,215 -- -- 85,215 (pound)5.99 -- May 15, 01 May 15, 07
EDIP 312,171 -- -- 312,171 (pound)5.67 -- Feb 19, 02 Feb 19, 08
Dr B E Grote(a) SAR 40,000 -- -- 40,000 $13.63 -- Mar 23, 96 Mar 23, 03
SAR 40,800 -- -- 40,800 $16.63 -- Mar 25, 97 Mar 25, 04
SAR 35,600 -- -- 35,600 $19.16 -- Feb 28, 98 Feb 28, 05
SAR 35,200 -- -- 35,200 $25.27 -- Mar 6, 99 Mar 6, 06
SAR 40,000 -- -- 40,000 $33.34 -- Feb 28, 00 Feb 28, 07
BPA 10,404 -- -- 10,404 $53.90 -- Mar 15, 00 Mar 14, 09
BPA 12,600 -- -- 12,600 $48.94 -- Mar 28, 01 Mar 27, 10
EDIP 40,182 -- -- 40,182 $49.65 -- Feb 19, 02 Feb 19, 08
EDIP -- 58,173 -- 58,173 $48.82 -- Feb 18, 03 Feb 18, 09
R L Olver SAYE 2,386 -- -- 2,386 (pound)2.89 -- Sept 1, 02 Feb 28, 03
SAYE 1,137 -- -- 1,137 (pound)5.11 -- Sept 1, 04 Feb 28, 05
SAYE -- 840 -- 840 (pound)4.52 -- Sept 1, 05 Feb 28, 06
EDIP 71,847 -- -- 71,847 (pound)5.99 -- May 15, 01 May 15, 07
EDIP 260,319 -- -- 260,319 (pound)5.67 -- Feb 19, 02 Feb 19, 08
EDIP -- 370,956 -- 370,956 (pound)5.72 -- Feb 18, 03 Feb 18, 09
Director leaving the board in 2002
Dr J G S Buchanan(b) SAYE 1,856 -- -- 1,856 (pound)3.71 -- Sept 1, 03 Feb 28, 04
SAYE 750 -- -- 750 (pound)4.49 -- Sept 1, 04 Feb 28, 05
SAYE 1,320 -- -- 1,320 (pound)5.11 -- Sept 1, 06 Feb 28, 07
EDIP 75,189 -- -- 75,189 (pound)5.99 -- May 15, 01 May 15, 07
EDIP 253,971 -- -- 253,971 (pound)5.67 -- Feb 19, 02 Feb 19, 08
W D Ford(a)(c) NRSO 105,866 -- -- 105,866 $20.80 -- Mar 22, 95 Mar 22, 04
NRSO 119,100 -- -- 119,100 $23.69 -- Mar 28, 96 Mar 28, 05
NRSO 132,332 -- -- 132,332 $27.68 -- Mar 26, 97 Mar 26, 06
NRSO 132,332 -- -- 132,332 $34.08 -- Mar 25, 98 Mar 25, 07
NRSO 132,332 -- -- 132,332 $32.92 -- Mar 24, 99 Mar 24, 08
BPA 54,712 -- -- 54,712 $53.90 -- Mar 15, 00 Mar 14, 09
BPA 38,750 -- -- 38,750 $48.94 -- Mar 28, 01 Mar 27, 10
EDIP 43,506 -- -- 43,506 $49.65 -- Feb 19, 02 Feb 19, 08
---------------
The closing market prices of an ordinary share and of an ADS on December
31, 2002 were (pound)4.27 and $40.65 respectively. During 2002, the highest
market prices were (pound)6.25 and $53.88 respectively, and the lowest market
prices were (pound)3.93 and $36.78 respectively.
EDIP -- Executive Directors' Incentive Plan adopted by shareholders in April
2000 as described in this item. The awards take into consideration the
ranking of the company's TSR against the TSR of the FTSE Global 100
group of companies over the three-year period prior to the grant. As
noted in last year's report, for directors who retire after January 1,
2002, options that are vested at a director's retirement will now be
preserved until the normal lapse date (the seventh anniversary of
grant).
BPA -- BP Amoco share option plan which applied to US executive directors prior
to the adoption of the EDIP.
NRSO -- Amoco Non-Restricted Stock Option Plan which applied to Mr Ford as an
employee of Amoco.
SAR -- Stock Appreciation Rights under BP America Inc. Share Appreciation Plan.
In keeping with the US market practice, none of the options under the BPA,
NRSO and SAR is subject to performance conditions because they were granted
under American plans to the relevant individuals and the NRSO options were
awarded prior to Amoco's merger with BP.
SAYE -- Save as You Earn employee share option scheme. These options are not
subject to performance conditions because this is an all-employee share
scheme governed by specific tax legislation.
---------------
(a) Numbers shown are ADSs under option. One ADS is equivalent to six ordinary
shares.
(b) On leaving the board of BP p.l.c. on November 21, 2002.
(c) On leaving the board of BP p.l.c. on March 31, 2002.
Page 109
Pensions
In the table below, amounts are shown in both US dollars and pounds
sterling and are converted at the rate of (pound)1 = $1.44 for 2001 and (pound)1
= $1.50 for 2002. Lord Browne, Mr Chase, Mr Olver and Dr Buchanan accrued
pension benefits in pounds sterling (the currency of payment). Similarly, Dr
Grote and Mr Ford accrued pension benefits in US dollars.
Amount
Additional Transfer Transfer of A-B less
Accrued pension value value contributions
pension earned during of accrued of accrued made by the
Service at entitlement the year ended benefits at benefits at director
Dec 31, 2002 at Dec 31, 2002 Dec 31, 2002 Dec 31, 2002(a) Dec 31, 2001(b) in 2002
------------ --------------- -------------- ------------ ------------ -------------
(thousand)
The Lord Browne of Madingley (UK).($) 36 years $1,284 $84 $19,143 $16,335 $2,808
(pounds)........................... 856 56 12,762 11,344 1,418
Dr J G S Buchanan (UK)............($) 33 years $520 $40 $9,586 $8,652 $934
(pounds)........................... 347 27 6,391 6,008 383
R F Chase (UK)....................($) 38 years $640 $50 $11,649 $10,633 $1,016
(pounds)........................... 427 33 7,766 7,384 382
W D Ford (USA) (a)................($) 31 years $644 $140 $8,324 $5,988 $2,336
(pounds)........................... 429 93 5,549 4,158 1,391
Dr B E Grote (USA)................($) 23 years $263 $181 $3,493 $1,069 $2,424
(pounds)........................... 175 121 2,329 742 1,587
R L Olver (UK)....................($) 29 years $530 $40 $8,210 $6,955 $1,255
(pounds)........................... 353 27 5,473 4,830 643
----------
(a) 2002 figures for Mr Ford are stated as at March 31, 2002, the date he left
the board of BP p.l.c. He retired in June 2002 and, in accordance with his
entitlements under the normal rules of the `grandfathered' plan, he took a
lump-sum distribution in August 2002 of his combined plan benefits
totalling $8,485,733.
UK Directors
UK directors are members of the BP Pension Scheme. The scheme offers Inland
Revenue-approved retirement benefits based on final salary. It is the principal
section of the BP Pension Fund, the latter being set up under trust deed.
Company contributions to the fund are made on the advice of the actuary
appointed by the trustee. No company contributions were made during 2002.
Scheme members' core benefits are non-contributory. They include a pension
accrual of 1/60th of basic salary for each year of service, subject to a maximum
of two-thirds of final basic salary; a lump-sum death-in-service benefit of 3 x
salary; and a dependant's benefit of two-thirds of the member's pension. The
scheme pension is not integrated with state pension benefits.
Normal retirement age is 60, but scheme members who have 30 or more years'
pensionable service at age 55 can elect to retire early without an actuarial
reduction being applied to their pension.
Pensions payable from the fund are guaranteed to be increased annually in
line with changes in the Retail Prices Index, up to a maximum of 5% a year.
Directors appointed prior to 2003 accrue pension on a non-contributory
basis at the enhanced rate of 2/60ths of their final salary for each year of
service as executive directors (up to the same two-thirds limit). None of the
directors is affected by the pensionable earnings cap.
Page 110
US Directors
In accordance with the Company's long-standing practice for executive
directors who retire from BP on or after age 55 having accrued at least 30
years' service, Mr Chase will receive an ex-gratia lump-sum superannuation
payment from the Company equal to one year's base salary following his
retirement. Lord Browne will remain eligible for consideration for such a
payment. In the case of these individuals, all matters relating to such
superannuation payments will be considered by the remuneration committee. Any
such payments would be in addition to their pension entitlements referred to
above. None of the other executive directors are eligible for consideration for
a superannuation payment on retirement, as the remuneration committee decided in
1996 that appointees to the board after that time should cease to be eligible
for consideration for such a payment.
US directors participate in the BP Retirement Accumulation Plan (US plan),
which features a cash balance formula. The current design of the US plan became
effective on July 1, 2000. However, certain former employees of Amoco and ARCO
have been provided with a minimum (or 'grandfathered') benefit equal to the
benefit that would have accrued under the respective predecessor pension plan.
Mr Ford's pension benefit was subject to this 'grandfathered' arrangement
described above, reflecting his Amoco service and benefits.
Consistent with US tax regulations, pension benefits are provided through a
combination of tax-qualified and non-qualified benefit restoration plans, as
applicable.
The Supplemental Executive Retirement Benefit (supplemental plan) is a
non-qualified top-up arrangement that became effective on January 1, 2002 for US
employees above a specified salary level. The benefit formula is 1.3% of final
average earnings, which comprise base salary and bonus in accordance with
standard US practice (as specified under the qualified arrangement) multiplied
by years of service, with an offset for benefits payable under all other BP
qualified and non-qualified pension arrangements. This benefit is unfunded and
therefore paid from corporate assets.
Dr Grote is an eligible participant under the supplemental plan, and his
pension accrual for 2002 includes the total amount that may become payable under
all plans.
Executive Directors' Shareholdings
Executive directors' interest in BP ordinary At January 1, 2002 Change from
shares or calculated equivalents At or on December 31, 2002
December 31, 2002 appointment to March 19, 2003
----------------- ------------------ -----------------
Current directors
(excluding those appointed in 2003)
The Lord Browne of Madingley..................... 1,681,652 (a) 1,392,184 (a) 134,400
R F Chase........................................ 810,826 794,745 83,802
Dr B E Grote..................................... 722,562 (b) 595,845 (b) 40,800
R L Olver........................................ 738,563 585,852 58,229
At
On retirement (c) January 1, 2002
------------- ---------------
Directors leaving the board in 2002
Dr J G S Buchanan................................ 890,409 723,149
W D Ford......................................... 435,607 (b) 333,139 (b)
Change from
On appointment February 1, 2003
on February 1, 2003 to March 19, 2003
------------------- -----------------
Directors appointed in 2003
Dr D C Allen..................................... 306,565 (d) 64,800
A B Hayward...................................... 91,777 24,192
J A Manzoni...................................... 95,552 24,192
----------
(a) Includes 50,368 Ordinary Shares held as ADSs throughout 2002.
(b) Held as ADSs.
(c) At retirement on November 21, 2002 and March 31, 2002 respectively.
(d) Includes 25,368 shares held as ADSs.
Page 111
In disclosing the above interests to the Company under the Companies Act
1985, directors did not distinguish their beneficial and non-beneficial
interests.
Executive directors are also deemed to have an interest in such shares of
the Company held from time to time by BP QUEST Company Limited and The BP
Employee Share Ownership Plan (No. 2) to facilitate the operation of the
Company's option schemes.
No director has any interest in the preference shares or debentures of the
Company, or in the shares or loan stock of any subsidiary company.
Service Contracts
The committee's policy on executive directors' service contracts is for
them to contain a maximum notice period of one year. To reflect current market
practice, Lord Browne has agreed to reduce the notice period in his contract to
one year and it has been amended to reflect this. All executive directors'
service contracts now either expire this year or can be terminated on one year's
notice.
Each service contract expires at the respective normal retirement date of
the director but is subject to earlier termination for cause or if notice is
given under the contract.
The contracts are designed to allow for flexibility to deal with each case
on its own particular merits in accordance with the law and policy as they have
developed at the relevant time. With effect from January 2003, the committee
will include a provision in new service contracts to allow for severance
payments to be phased where appropriate to do so. It will also consider
mitigation to reduce compensation to a departing director where appropriate to
do so. A large proportion of each executive director's total remuneration is
linked to performance and therefore will not be payable to the extent that
relevant targets are not met.
Remuneration of Non-Executive Directors
During 2002, the board appointed a committee of independent non-executive
directors to review the remuneration of the non-executive directors and make
recommendations for future structure and amount.
Policy
In making recommendations for non-executive directors' remuneration, the
following policies were developed to guide the board in its current and future
decision-making.
-- Within the limits sets by the shareholders from time to time,
remuneration should be sufficient to attract, motivate and retain
world-class non-executive talent.
-- Remuneration of non-executive directors should be proportional to
their contribution towards the interests of the Company.
-- Remuneration practice should be consistent with recognized
best-practice standards for non-executive directors' remuneration.
-- Remuneration should be in the form of cash fees, payable monthly.
-- Non-executive directors should not receive share options from the
Company.
-- Non-executive directors should be encouraged to establish a holding in
BP shares broadly related to one year's base fee, to be held directly
or indirectly in a manner compatible with their personal investment
activities and any applicable legal and regulatory requirements.
Page 112
Elements of Remuneration
In contrast to the position of executive directors' pay, in which an
increasing element is performance-related, non-executive directors' pay
comprises cash fees, paid monthly, with increments for positions of additional
responsibility, reflecting additional workload and consequent potential
liability. For all non-executive directors except the chairman, a fixed sum
allowance is paid for transatlantic travel undertaken for the purpose of
attending a board meeting. In addition, non-executive directors receive
reimbursement of reasonable travel and related business expenses. No share or
share option awards are made to any non-executive director in respect of service
on the board. Non-executive directors have letters of appointment that recognize
that, subject to the Articles of Association, their service is at the discretion
of the shareholders. They submit themselves for election at the annual general
meeting following their appointment and subsequently at intervals of no more
than three years.
Non-executive Directors' Annual Fee Structure
The Company's Articles provide that the remuneration paid to non-executive
directors is determined by the board within limits set by shareholders. Fees
payable to non-executive directors were reviewed during 2002. New and increased
fees based on a comparable structure were approved by the board as from July 1,
2002. All fees are fixed and paid in pounds sterling. For conformity these are
also reported in US dollars.
To June 30, 2002 From July 1, 2002
$(a) (pound) $ (a) (pound)
--------------- -----------------
(thousands)
Chairman................................ 420 280 585 390 (b)
Deputy chairman......................... 128 85 128 85 (c)
Board member............................ 68 45 98 65
Committee chairmanship fee.............. 8 5 23 15
Transatlantic attendance allowance (d).. 5 3 8 5
------ ------ ------ ------
----------
(a) Sterling payments converted at the average 2002 exchange rate of (pound)1 =
$1.50.
(b) The chairman is not eligible for committee chairmanship fees or
transatlantic attendance allowance but has the use of a fully maintained
office and a chauffered car for company business.
(c) The deputy chairman receives a (pound)20,000 increment on top of the
standard board fee. In addition, this is supplemented by committee
chairmanship fees and the transatlantic attendance allowance. The deputy
chairman is currently chairman of the Audit Committee. Prior to July 1,
2002, the deputy chairman received an all-inclusive fee of (pound)85,000
and was ineligible for both committee chairmanship fees and the
transatlantic attendance allowance.
(d) This allowance is payable to non-executive directors undertaking
transatlantic travel for the purpose of attending a board meeting or board
committee meeting.
Page 113
2002 2001
Remuneration of Non-Executive Directors $(a) (pound) $(b) (pound)
---------------- -----------------
(thousands)
Current directors
J H Bryan....................................... 120 80 82 57
E B Davis, Jr................................... 120 80 82 57
Dr D S Julius................................... 95 63 6 4
C F Knight...................................... 95 63 78 54
F A Maljers..................................... 95 63 78 54
Dr W E Massey................................... 135 90 94 65
H M P Miles (c)................................. 95 63 78 54
Sir Robin Nicholson (d)......................... 110 73 83 57
Sir Ian Prosser................................. 147 98 122 85
P D Sutherland.................................. 503 335 403 280
M H Wilson...................................... 116 77 86 60
------ ------ ------ ------
Directors leaving the board in 2002
Sir Robert Wilson............................... 27 18 73 51
====== ====== ====== ======
----------
(a) Sterling payments converted at the average 2002 exchange rate of (pound)1 =
$1.50.
(b) Sterling payments converted at the average 2001 exchange rate of (pound)1 =
$1.44.
(c) Also received (pound)300 in 2001 ($432 at 2001 rate) and (pound)600 in 2002
($900 at 2002 rate) for serving as a director of BP Pension Trustees
Limited.
(d) Also received (pound)20,000 each year ($28,800 at 2001 rate; and $30,000 at
2002 rate) for serving as the board's representative on the Technology
Advisory Council.
Long-term Incentives (residual)
Non-executive directors of Amoco Corporation were allocated restricted
stock in the Amoco Non-Employee Directors' Restricted Stock Plan by way of
remuneration for their service on the board of Amoco Corporation prior to its
merger with BP in 1998. On merger, interests in Amoco shares in the plan were
converted into interests in BP ADSs. Under the terms of the plan, the restricted
stock will vest upon the retirement of the non-executive director at age 70 or
upon earlier retirement at the discretion of the board. Since the merger, no
further entitlements have accrued to any director under the plan.
Amoco Non-Employee Directors' Restricted Stock Plan
The table below sets out the residual entitlements of non-executive
directors who were formerly non-executive directors of Amoco Corporation under
the Amoco Non-Employee Directors' Restricted Stock Plan.
Interest in BP ADSs
January 1, 2002 and Date on which director
December 31, 2002(a) reaches age 70(b)
------------------- ----------------------
J H Bryan 5,546 October 5, 2006
E B Davis, Jr 4,490 August 5, 2014
F A Maljers 2,906 August 12, 2003
Dr W E Massey 3,346 April 5, 2008
M H Wilson 3,170 November 4, 2007
----------
(a) No awards were granted or vested and no awards lapsed during the year.
(b) If the director retires prior to this date, the board may waive the
restrictions.
Page 114
Superannuation Gratuities
In accordance with BP's long-standing practice, non-executive directors who
retire from the board after at least six years' service are, at the time of
their retirement, eligible for consideration for a superannuation gratuity. The
board is authorized to make such payments under the Company's Articles. The
amount of payment is determined at the board's discretion, having regard to the
director's period of service as a director and other relevant factors. The board
did not make any payment to Sir Robert Wilson, the only non-executive director
retiring in 2002, in view of his limited length of service.
On the recommendation of the ad hoc committee on non-executive
remuneration, during 2002 the board revised its policy with respect to such
payments so that (i) non-executive directors appointed to the board after July
1, 2002 would not be eligible for consideration for such a payment, and (ii)
non-executive directors in service at July 1, 2002 would remain eligible for
consideration for a payment, but service after that date would not be taken into
account by the board in considering the amount of any payment.
Non-Executive Directors' Shareholding
Non-Executive Directors' interest in BP ordinary At January 1, 2002 Change from
shares or calculated equivalents At or on December 31, 2002
December 31, 2002 appointment to March 19, 2003
----------------- ------------------ -----------------
Current directors
J H Bryan............................................ 98,760 (a) 98,760 (a) 60,000
E B Davis, Jr........................................ 63,814 (a) 62,695 (a) --
Dr D S Julius........................................ 2,000 2,000 --
C F Knight........................................... 92,238 (a) 30,247 (a) --
F A Maljers.......................................... 33,492 (a) 33,492 (a) --
Dr W E Massey........................................ 48,232 (a) 47,378 (a) --
H M P Miles.......................................... 22,145 9,445 --
Sir Robin Nicholson.................................. 3,758 3,643 --
Sir Ian Prosser...................................... 2,826 2,826 4,475
P D Sutherland....................................... 7,079 7,079 --
M H Wilson........................................... 43,200 (a) 43,200 (a) --
At
On retirement (b) January 1, 2002
--------------- ---------------
Directors leaving the board in 2002
Sir Robert Wilson.................................... 5,478 5,478
----------
(a) Held as ADSs.
(b) At retirement on April 18, 2002.
In disclosing the above interests to the Company under the Companies Act
1985, directors did not distinguish their beneficial and non-beneficial
interests.
No director has any interest in the preference shares or debentures of the
Company, or in the shares or loan stock of any subsidiary company.
Total Remuneration
Total remuneration includes salary and benefits earned and paid during the
relevant year, plus bonuses, which are paid in the following year, plus for 2002
the value of the awards made under the 1999 to 2001 Long Term Performance Plan
in respect of the three years covered by that plan. The total remuneration paid
during 2002 to all directors and senior management as a group was $35.5 million.
Total share options granted during 2002 to all directors and senior management
as a group was 3,047,547; these have an option price of (pound)5.72 and expire
in 2012.
Page 115
BOARD PRACTICES
Period during which the
director has served in
Date of expiration of this office (from
Directors' Terms of Office current term of office appointment to April 2003)
---------------------- --------------------------
Dr D C Allen................................... -- 2 months
The Lord Browne of Madingley................... April 2004 11 years 7 months
J H Bryan (a).................................. April 2005 4 years 4 months
R F Chase...................................... Retires April 2003 11 years 1 month
E B Davis, Jr (a).............................. April 2005 4 years 4 months
Dr B E Grote................................... April 2004 2 years 9 months
Dr A B Hayward................................. -- 2 months
Dr D S Julius.................................. April 2005 1 year 5 months
C F Knight..................................... April 2003 15 years 7 months
F A Maljers (a)................................ April 2005 4 years 4 months
J A Manzoni.................................... -- 2 months
Dr W E Massey (a).............................. April 2005 4 years 4 months
H M P Miles.................................... April 2004 8 years 11 months
Sir Robin Nicholson............................ April 2004 15 years 7 months
R L Olver...................................... April 2004 5 years 4 months
Sir Ian Prosser................................ April 2004 6 years
P D Sutherland................................. April 2005 7 years 8 months
M H Wilson (a)................................. April 2005 4 years 4 months
----------
(a) Does not include service on the board of Amoco Corporation.
Directors' Service Contracts Providing for Benefits upon Termination of
Employment
Executive directors are employees of the Company or one of its subsidiaries
under a variety of contracts of service. The contracts of service for executive
directors provides for one year's notice to be given of termination of the
contract or, in some circumstances, payment of one year's salary in lieu of
notice. There are two exceptions to this: Mr R F Chase and Mr W D Ford. Mr Chase
has a contract that provides for two year's notice of termination, however this
contract expires at his normal retirement date of May 2003. Mr Ford resigned
from the board of BP p.l.c. with effect from March 31, 2002, at which time his
secondment to BP p.l.c. ended and he returned to the USA. His underlying US
employment agreement with BP Corporation North America (BPCNA) had a two-month
notice period and was due to expire on January 21, 2004. His contract was
terminated early by BPCNA in accordance with its terms. The contract terms
required payment to him by BPCNA of liquidated damages of $1,655,555, being
equivalent to $1 million per annum (pro rated for part years) for each year
between the date of severance and January 21, 2004. BPCNA also made payments
totalling $129,691 to Mr Ford in June 2002 in accordance with its standard
benefits and repatriation programme. Mr Ford remains eligible for a pro rata
award under the 2002 annual bonus scheme and for awards under the long-term
incentive schemes in accordance with the rules of those schemes.
Non-executive directors do not have service contracts with the Company;
they are not employees of the Company. Non-executive directors are not entitled
to any benefits on termination of office.
Page 116
Corporate Governance Statement
General
The board's governance policies regulate its relationship with
shareholders, the conduct of board affairs and its relationship with the group
chief executive. The policies recognize that the board has a separate and unique
role as the link in the chain of authority between the shareholders and the
group chief executive. In addition, they acknowledge the dual role played by the
group chief executive and executive directors as both members of the board and
leaders of the executive management. The policies therefore require a majority
of the board to be composed of non-executive directors and delegate all aspects
of the relationship between the board and the group chief executive to the
non-executive directors. The policies also require the chairman and deputy
chairman to be non-executive directors; throughout 2002 the posts were held by
Mr Sutherland and Sir Ian Prosser respectively. Sir Ian Prosser acts as the
senior independent non-executive director as required by the Combined Code on
Corporate Governance. Finally, the company secretary reports to the
non-executive chairman and is not part of the executive management.
Relationship with Shareholders
The policies emphasize the importance of the relationship between the board
and the shareholders. In them the board acknowledges that its role is to
represent and promote the interests of shareholders and that it is accountable
to shareholders for the performance and activities of the Group (including, for
example, the system of internal control and the review of its effectiveness).
The board is required to be proactive in obtaining an understanding of
shareholder preferences and to evaluate systematically the economic, social,
environmental and ethical matters that may influence or affect the interests of
its shareholders. These interests are represented and promoted by the board
through exercising its policy-making and monitoring functions. As a result,
shareholder interests lie at the heart of the goals established by the board for
the Company.
The board is accountable to shareholders in a variety of ways. Directors
are required to stand for re-election every three years to ensure that
shareholders have a regular opportunity to reassess the composition of the
board. New directors are subject to election at the first opportunity following
their appointment. Names submitted to shareholders for election in 2002 were
accompanied by biographical details.
The board makes use of a number of formal channels of communication to
account to shareholders for the performance of the Company. These include the
Annual Report and Accounts, the Annual Report on Form 20-F filed with the US
Securities and Exchange Commission, quarterly announcements made through stock
exchanges on which BP shares are listed and the annual general meeting of
shareholders. Given the size and geographical diversity of BP's shareholder
base, the opportunities for shareholder interaction at the annual general
meeting are limited. However, the chairman and all board committee chairmen were
present at the 2002 annual general meeting to answer questions. All proxy votes
at shareholder meetings are counted since votes on all matters except procedural
issues are taken by way of a poll. BP has also pioneered the use of electronic
communications to facilitate the exercise of shareholder voting rights.
Presentations given at appropriate intervals to representatives of the
investment community are available simultaneously to all shareholders by live
internet broadcast or open conference call.
Page 117
Board Process
The board has laid down rules for its own activities in a board process
policy that covers the conduct of members at meetings; the cycle of board
activities and the setting of agendas; the provision of information to the
board; board officers and their roles; board committees, their tasks and
composition; qualifications for board membership and the process of the
Nomination Committee; the remuneration of non-executive directors; the
appointment and role of the company secretary; the process for directors to
obtain independent advice and the assessment of the board's performance. The
board process policy places responsibility for implementation of this policy,
including training of directors, on the chairman.
The policy recognizes that the board's capacity, as a group, is limited.
The board therefore reserves to itself the making of broad policy decisions,
delegating more detailed considerations involved in meeting its stated
requirements either to board committees and officers (in the case of its own
processes) or to the group chief executive (in the case of the management of the
Company's business activity). The policy allocates the tasks of monitoring
executive actions and assessing reward to the following committees:
-- Chairman's Committee (all non-executive directors) - to review the
structure and effectiveness of the business organization; succession
planning for the executive directors and the most senior executives;
and to assess the overall performance of the group chief executive.
The committee met four times during 2002.
-- Audit Committee (four to six non-executive directors) - to monitor all
reporting, accounting, control and financial aspects of the executive
management's activities. The auditors' lead partner and the BP general
auditor (head of internal audit) attend each meeting at the request of
the committee chairman. The committee met 10 times during 2002.
-- Ethics and Environment Assurance Committee (four to six non-executive
directors) - to monitor the non-financial aspects of the executive
management's activities. The auditors' lead partner and the BP general
auditor (head of internal audit) attend each meeting at the request of
the committee chairman. The committee met four times during 2002.
-- Remuneration Committee (four to six non-executive directors) - to
determine performance contracts, targets and the structure of the
rewards for the group chief executive and the executive directors and
to monitor the policies being applied in remunerating other senior
executives. The committee met five times during 2002.
-- Nomination Committee (the chairman, group chief executive and three
non-executive directors selected from time to time as required) - to
identify, evaluate and recommend candidates for appointment or
reappointment as directors and as company secretary. The committee met
once during 2002.
The qualification for board membership includes a requirement that
non-executive directors be free from any relationship with the executive
management of the Company that could materially interfere with the exercise of
their independent judgement. In the board's view, all non-executive directors
fulfil this requirement. The board met nine times during 2002, six times in the
UK, twice in the USA and once in Europe for a two-day strategy discussion.
Committee meetings are held in conjunction with board meetings whenever
possible.
In carrying out its work, the board has to exercise judgement about how
best to further the interests of shareholders. Given the uncertainties inherent
in the future of business activity, the board seeks to maximize the expected
value of the shareholders'interest in the Company, not to eliminate the
possibility of any adverse outcomes for shareholders.
Page 118
Board/Executive Relationship
The board/executive relationship policy sets out how the board delegates
authority to the group chief executive and the extent of that authority. In its
goals policy, the board states the long-term outcome it expects the group chief
executive to deliver. The restrictions on the manner in which the group chief
executive may achieve the required results are set out in the executive
limitations policy, which addresses ethics, health, safety, the environment,
financial distress, internal control, risk preferences, treatment of employees
and political considerations. On all these matters, the board's role is to set
general policy and to monitor the implementation of that policy by the group
chief executive.
The group chief executive explains how he intends to deliver the required
outcome in annual and medium-term plans, the former of which include a
comprehensive assessment of the risks to delivery. Progress towards the expected
outcome is set out in a monthly report that covers actual results and a forecast
of results for the current year. This report is reviewed at each board meeting.
The board/executive relationship policy also sets out how the group chief
executive's performance will be monitored and recognizes that, in the multitude
of changing circumstances, judgement is always involved. The group chief
executive is obliged through dialogue and systematic review to discuss with the
board all material matters currently or prospectively affecting the Company and
its performance and all strategic projects or developments. This specifically
includes any materially under-performing business activities and actions that
breach the executive limitations policy. It also includes social, environmental
and ethical considerations. This dialogue is a key feature of the
board/executive relationship. Between board meetings the chairman has
responsibility for ensuring the integrity and effectiveness of the
board/executive relationship. The systems set out in the board/executive
relationship policy are designed to manage rather than eliminate the risk of
failure to achieve the board goals policy or observe the executive limitations
policy. They provide reasonable, not absolute, assurance against material
misstatement or loss.
Audit Committee
The committee is comprised of five non-executive directors: Sir Ian Prosser
(Chairman), Mr Bryan, Mr Davis Jr, Mr Miles and Mr Wilson. The Secretary of the
Audit Committee, Miss Judith Hanratty (Company Secretary) is independent of the
executive management of the Company and reports to the non-executive chairman.
The committee's task as set out in the board governance policies are:
-- To monitor systematically and obtain assurance that the legally
required standards of disclosure are being fully and fairly observed.
-- To review all prospectuses, information and offering memoranda and
other documents to be placed before shareholders and make
recommendations to the board about their adoption and publication.
-- To review all annual, quarterly and similar reports to shareholders
and make recommendations to the board about their adoption and
publication.
-- To monitor systematically and obtain assurance that the Executive
Limitations set out in the Board Governance Policies relating to
financial matters are being observed.
The committee keeps under review the scope and results of audit work, its
cost-effectiveness and the independence and objectivity of the auditors. It
requires the auditors to rotate their lead audit partner every five years and
reviews non-audit assignments. Aside from its monitoring of external audit work,
the committee considers the internal audit programme.
Page 119
Remuneration Committee
The committee's tasks as set out in the board governance policies are:
-- To determine on behalf of the board the terms of engagement and
remuneration of the group chief executive and the executive directors
and to report on those to the shareholders.
-- To determine on behalf of the board matters of policy over which the
Company has authority relating to the establishment or operation of
the Company's pension scheme of which the executive directors are
members.
-- To nominate on behalf of the board any trustees (or directors of
corporate trustees) of such scheme.
-- To monitor the policies being applied by the group chief executive in
remunerating senior executives other than executive directors.
Constitution and Operation
The committee members are all non-executive directors. The membership
throughout 2002 was: Sir Robin Nicholson (chairman), Mr Davis, Dr Julius, Mr
Knight and Sir Ian Prosser. Like other directors, each member of the committee
is subject to re-election every three years. They have no personal financial
interest, other than as shareholders, in the committee's decisions. They have no
conflicts of interest arising from cross-directorships with the executive
directors nor from being involved in the day-to-day business of the Company. The
committee met five times in the period under review.
In its constitution and operation the committee complies with the Combined
Code on Corporate Governance. It is accountable to shareholders through its
annual report on executive directors' remuneration. The committee will consider
the outcome of the vote on the remuneration report at the 2003 Annual General
Meeting, and the views of investors will be taken into account by the committee
in its future decisions.
Page 120
EMPLOYEES
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
Number of employees at December 31,
2002
Exploration and Production.................. 3,500 800 5,500 7,000 16,800
Gas, Power and Renewables................... 250 1,000 1,500 1,650 4,400
Refining and Marketing ..................... 9,950 23,300 28,100 12,000 73,350
Chemicals................................... 2,800 4,750 6,650 3,700 17,900
Other businesses and corporate.............. 1,250 -- 1,450 100 2,800
-------- -------- -------- -------- --------
17,750 29,850 43,200 24,450 115,250
======== ======== ======== ======== ========
2001
Exploration and Production.................. 3,700 800 5,550 6,500 16,550
Gas, Power and Renewables................... 650 650 1,350 1,550 4,200
Refining and Marketing ..................... 10,450 15,100 27,800 11,250 64,600
Chemicals................................... 3,450 6,250 6,700 5,550 21,950
Other businesses and corporate.............. 1,400 -- 1,350 100 2,850
-------- -------- -------- -------- --------
19,650 22,800 42,750 24,950 110,150
======== ======== ======== ======== ========
2000
Exploration and Production.................. 3,300 700 5,900 6,100 16,000
Gas, Power and Renewables................... 500 500 1,500 900 3,400
Refining and Marketing ..................... 10,100 16,800 27,000 13,200 67,100
Chemicals................................... 3,700 4,500 7,900 1,500 17,600
Other businesses and corporate.............. 1,300 -- 1,700 100 3,100
-------- -------- -------- -------- --------
18,900 22,500 44,000 21,800 107,200
======== ======== ======== ======== ========
Employee numbers increased slightly during 2002, mainly as a result of the
Veba acquisition. 2001 increases primarily related to the acquisition of Bayer's
50% interest in Erdoelchemie, the Solvay transaction and the inclusion of the
Burmah Castrol chemicals businesses previously held for sale, were partly offset
by downstream rationalization and a further decrease in former ARCO employees.
The acquisitions of ARCO and Burmah Castrol in 2000 increased our employee
numbers by approximately 25,000.
The Company seeks to maintain constructive relationships with labor unions.
Page 121
SHARE OWNERSHIP
Directors and Senior Management
As at March 19, 2003 the following directors of BP p.l.c. held interests in
BP ordinary shares of 25 cents each or their calculated equivalent as set out
below:
Dr D C Allen................................ 371,365
The Lord Browne of Madingley................ 1,816,052
R F Chase................................... 894,628
Dr B E Grote................................ 763,362
Dr A B Hayward.............................. 115,969
J A Manzoni................................. 119,744
R L Olver................................... 796,792
J H Bryan................................... 158,760
E B Davis, Jr............................... 63,814
Dr D S Julius............................... 2,000
C F Knight.................................. 92,238
F A Maljers................................. 33,492
Dr W E Massey............................... 48,232
H M P Miles................................. 22,145
Sir Robin Nicholson......................... 3,758
Sir Ian Prosser............................. 7,301
P D Sutherland.............................. 7,079
M H Wilson.................................. 43,200
As at March 19, 2003, the following directors of BP p.l.c. held
options under the BP Group share option schemes for ordinary shares or their
calculated equivalent as set out below:
Dr D C Allen................................ 519,950
The Lord Browne of Madingley................ 4,378,090
R F Chase................................... 400,774
Dr B E Grote................................ 1,077,192(a)
Dr A B Hayward.............................. 494,702
J A Manzoni................................. 517,478
R L Olver................................... 1,076,055
---------------
(a) In addition to the above, Dr Grote holds 151,600 Stock Appreciation Rights
(equivalent to 909,600 Ordinary Shares).
There are no directors or members of senior management who own more than 1%
of the Ordinary Shares outstanding.
Additional details regarding the options granted, including exercise price
and expiry dates, are found in this item under the heading `Compensation --
Share Option Element and Other Option Schemes.'
Employee Share Plans
2002 2001 2000
------- ------- -------
(options thousands)
Employee share options granted during the year
Savings related schemes..................................... 9,719 7,901 7,930
Executive Directors' Incentive Plan......................... 2,068 2,598 709
BP Share Option Plan........................................ 66,771 58,208 50,461
------- ------- -------
78,558 68,707 59,100
======= ======= =======
The exercise prices for BP options granted during the year were
(pound)4.52/$6.78 (9,719,005 options) for savings-related and similar plans;
(pound)5.67/$8.51 (weighted average price) for Executive Directors' Incentive
Plan (2,068,026 options); and (pound)5.50/$8.25 (weighted average price) for
66,770,545 options granted under the BP Share Option Plan.
Page 122
BP offers most of its employees the opportunity to acquire a shareholding
in the Company through savings-related and/or matching share plan arrangements.
Such arrangements are now in place in nearly 80 countries. BP also uses
long-term performance plans (see Item 18 -- Financial Statements -- Note 36) and
the granting of share options as elements of remuneration for executive
directors and senior employees.
During 2002, share options were granted to the executive directors under
the Executive Directors' Incentive Plan (EDIP). For these options the option
exercise price was the market value (as determined in accordance with plan
rules) on the grant date. The options granted to executive directors reflect
BP's performance in terms of total shareholder return (TSR), that is, share
price increase with all dividends reinvested, relative to the FTSE Global 100
group of companies over the three years preceding the grant. Options vest over
three years (one-third each after one, two and three years respectively) and
have a life of seven years after the grant.
Share options were also granted in 2002 under the BP Share Option Plan to
certain categories of employees. Subject to certain vesting requirements the
options are exercisable between the third and tenth anniversaries of the date of
grant. There are no performance conditions attaching to the options granted
during the year.
Under the BP ShareSave Plan (a savings-related share option plan) employees
save on a monthly basis over a three- or five-year period towards the purchase
of shares at a price fixed when the option is granted. The option price is
usually set at a 20% discount to the market price at the time of grant. The
option must be exercised within six months of maturity of the savings contract;
otherwise it lapses. The plan is run in the UK and a small number of other
countries.
Under the BP ShareMatch Plan, BP matches employees' own contributions of
shares, up to a predetermined limit. The shares are then held in trust for a
defined minimum period. The plan is run in the UK and in over 60 other
countries.
The Company sponsors a number of savings plans covering most US employees.
Under these plans, most employees may contribute up to 100% of their salary
subject to certain regulatory limits. Most employees are eligible for a
dollar-for-dollar company matched contribution for the first 7% of eligible pay
contributed on a before-tax or after-tax basis, or a combination of both. The
precise arrangement may vary in certain business units. Company contributions
are initially invested in a fund primarily comprised of BP ADSs but employees
may transfer those amounts and may invest their own contributions in more than
200 investment options. The Company's contributions generally vest over a period
of three years. Company contributions to savings plans during 2002 were $125
million (2001 $125 million and 2000 $101 million).
An Employee Share Ownership Plan was established in 1997 to acquire BP
shares to satisfy future requirements of certain employee share plans. The
Company provides funding to the ESOP. The assets and liabilities of the ESOP are
recognized as assets and liabilities of the Company within the accounts. The
ESOP has waived its rights to dividends.
During 2002, the ESOP released 15,332,235 shares (2001 11,508,754 shares
and 2000 9,412,931 shares) for the matching share plans. The cost of shares
released for these plans has been charged in these accounts. At December 31,
2002 the ESOP held 18,673,675 shares (2001 34,005,910 shares and 2000 45,514,664
shares).
BP has established a Qualifying Employee Share Ownership Trust (QUEST) to
support the UK ShareSave plans. During the year, contributions of $21 million
(2001 $36 million and 2000 $76 million) were made by the Company to the QUEST
which, together with option-holder contributions, were used by the QUEST to
subscribe for new ordinary shares at market price. The Company has transferred
the cost of this contribution directly to retained profits and the excess of the
subscription price over nominal value has increased the share premium account.
Page 123
At December 31, 2002, all the 9,443,842 Ordinary Shares issued to the QUEST
had been transferred to employees exercising options under the UK ShareSave
plan. Under new legislation, the QUEST can no longer be used for ShareSave plans
after December 31, 2002.
Pursuant to the various BP Group share option schemes, the following
options for BP ordinary shares of the Company were outstanding at March 19,
2003:
Expiry Exercise
Options dates of price
outstanding options per share
------------ ------------ ------------
(shares)
473,205,541 2003 to 2013 $3.47 to $9.97
Further details on share options appear in Item 18 -- Financial Statements
-- Note 35.
Page 124
ITEM 7 -- MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
Major Shareholders
At March 19, 2003, the Company has been notified that JPMorgan Chase Bank,
as depositary for American Depositary Shares (ADSs), holds interests through its
nominee, Guaranty Nominees Limited, in 6,537,438,628 Ordinary Shares (29.35% of
the Company's ordinary share capital). Included in this total is part of the
holding of the Kuwait Investment Office (KIO). Either directly or through
nominees, the KIO holds interests in 715,040,000 Ordinary Shares (3.21% of the
Company's ordinary share capital). The KIO does not have any different voting
rights from the rights of other ordinary shareholders.
Related Party Transactions
The Group had no material transactions with joint ventures and associated
undertakings during the period commencing January 1, 2002 to the date of this
filing. Transactions between the Group and its significant joint ventures and
associated undertakings are summarised in Item 18 -- Financial Statements --
Note 43.
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, 2002 to March
19, 2003.
ITEM 8 -- FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION
Financial Statements
See Item 18 -- Financial Statements.
Dividends
The total dividends announced for 2002 were $5,375 million, compared with
$4,935 million in 2001 and $4,625 million in 2000. Dividends per share for 2002
were 24.00 cents, compared with 22.00 cents per share in 2001 (an increase of
9.1%) and 20.50 cents per share in 2000 (an increase of 7.3% over 2000). The
board sets the dividend based on a balance of factors. It considers present
earnings, together with long-term growth prospects, cash flow and the Group's
competitive position.
Legal Proceedings
Save as disclosed in the following paragraphs, no member of the Group is a
party to, and no property of a member of the Group is subject to, any pending
legal proceedings which are significant to the Group.
Approximately 200 lawsuits were filed in State and Federal Courts in Alaska
seeking compensatory and punitive damages arising out of the Exxon Valdez oil
spill in Prince William Sound in March 1989. Most of those suits named Exxon
(now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the
oil terminal at Valdez, and the other oil companies which own Alyeska. Alyeska
initially responded to the spill until the response was taken over by Exxon. BP
owns a 47% interest (reduced during 2001 from 50% by a sale of 3% to Phillips)
in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned
a further 20% interest in Alyeska following BP's combination with Atlantic
Richfield Company (ARCO). Alyeska and its owners have settled all 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 will defend the claims vigorously.
Page 125
Since 1987, Atlantic Richfield Company (ARCO), a current subsidiary of BP,
has been named as a co-defendant in numerous lawsuits brought in the United
States alleging injury to persons and property caused by lead pigment in paint.
The majority of the lawsuits have been abandoned or dismissed as against ARCO.
ARCO (and in one case two of its affiliates) is named in these lawsuits as
alleged successor to International Smelting and Refining which, along with a
predecessor company, manufactured lead pigment during the period 1920-1946.
Plaintiffs include individuals and governmental entities. Several of the
lawsuits purport to be class actions. The lawsuits (depending on plaintiff) seek
various remedies including: compensation to lead-poisoned children; cost to find
and remove lead paint from buildings; medical monitoring and screening
programmes; public warning and education of lead hazards; reimbursement of
government healthcare costs and special education for lead-poisoned citizens;
and punitive damages. No case has been settled or tried to conclusion. While the
amounts claimed could be substantial and it is not possible to predict the
outcome of these legal actions, ARCO believes that it has valid defences and it
intends to defend such actions vigorously. Consequently, BP believes that the
impact of these lawsuits on the Group's results of operations, financial
position or liquidity will not be material.
For certain information regarding environmental proceedings see Item 4 --
Environmental Protection -- Legislation and Regulation -- United States.
SIGNIFICANT CHANGES
None.
ITEM 9 -- THE OFFER AND LISTING
Markets and Market Prices
The primary market for BP's ordinary shares is the London Stock Exchange
(LSE). BP's ordinary shares are a constituent element of the Financial Times
Stock Exchange 100 Index. BP's ordinary shares are also traded on stock
exchanges in France, Germany, Japan and Switzerland.
Trading of BP's shares on the LSE is primarily through the use of the Stock
Exchange Electronic Trading Service (SETS), introduced in 1997 for the largest
companies in terms of market capitalization whose primary listing is the LSE.
Under SETS, buy and sell orders at specific prices may be sent to the exchange
electronically by any firm which is a member of the LSE, on behalf of a client
or on behalf of itself acting as a principal. The orders are then anonymously
displayed in the order book. When there is a match on a 'buy' and a 'sell'
order, the trade is executed and automatically reported to the LSE. Trading is
continuous from 8:00 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 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 JPMorgan Chase Bank is the
depositary (the Depositary) and transfer agent. The Depositary's address is 1
Chase Manhattan Plaza, 40th Floor, New York, NY 10081, USA. 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. ADSs are
evidenced by American Depositary Receipts, or ADRs, which may be issued in
either certificated or book entry form.
Page 126
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 1998, and of BP p.l.c. for 1999, 2000, 2001 and 2002. These
are derived from the Daily Official List of the LSE, and the highest and lowest
sales prices of ADSs as reported on the New York Stock Exchange composite tape.
The information in this table has been changed to reflect the subdivision of BP
ordinary shares on October 4, 1999, whereby each Ordinary Share of $0.50 was
subdivided into two Ordinary Shares of $0.25.
American
Depositary
Ordinary shares Shares (a)
--------------- --------------
High Low High Low
---- --- ------ ----
(Pence) (Dollars)
Year ended December 31,
1998........................................ 484.25 368.50 48.66 36.50
1999........................................ 643.50 411.00 62.63 40.19
2000........................................ 671.00 444.50 60.63 43.13
2001........................................ 647.00 491.50 54.86 43.23
2002........................................ 625.00 392.50 53.88 36.78
Year ended December 31,
2001: First quarter...................... 609.00 526.50 53.49 46.64
Second quarter..................... 647.00 562.00 54.86 47.88
Third quarter...................... 610.50 504.00 52.80 44.20
Fourth quarter..................... 594.50 491.50 51.88 43.23
2002: First quarter...................... 625.00 511.00 53.10 43.84
Second quarter..................... 625.00 523.50 53.88 47.30
Third quarter...................... 559.50 418.00 50.86 39.32
Fourth quarter..................... 458.50 392.50 42.35 36.78
2003: First quarter (through March 19)... 429.00 356.50 41.88 35.37
Month of
September 2002.............................. 499.00 418.00 44.33 39.65
October 2002................................ 458.50 392.50 42.35 36.78
November 2002............................... 423.00 396.50 39.47 37.11
December 2002............................... 429.00 410.50 40.75 38.75
January 2003................................ 429.00 356.50 41.88 35.37
February 2003............................... 416.50 379.00 39.97 37.67
March 2003 (through March 19)............... 415.00 371.00 39.45 37.25
----------
(a) An ADS is equivalent to six Ordinary Shares.
Market prices for the BP ordinary shares on the LSE and in after-hours
trading off the LSE, in each case while the New York Stock Exchange is open, and
the market prices for ADSs on the New York Stock Exchange and other North
American stock exchanges, are closely related due to arbitrage among the various
markets, although differences may exist from time to time due to various factors
including UK stamp duty reserve tax. Trading in ADSs began on the LSE on August
3, 1987.
On March 19, 2003, 1,089,573,105 ADSs (equivalent to 6,537,438,628 BP
ordinary shares or some 32.4% of the total) were outstanding and were held by
approximately 177,000 registered ADR holders. Of these, about 175,000 had
registered addresses in the USA at that date. One of the registered holders of
ADSs represents some 525,000 underlying holders.
Page 127
On March 19, 2003 there were approximately 359,000 holders of record of
Ordinary Shares. Of these holders, around 1,500 had registered addresses in the
United States and held a total of some 4,644,000 Ordinary Shares.
Page 128
ITEM 10 -- ADDITIONAL INFORMATION
MEMORANDUM AND ARTICLES OF ASSOCIATION
The following summarizes certain provisions of BP's memorandum and articles
of association and applicable English law. This summary is qualified in its
entirety by reference to the UK Companies Act and BP's memorandum and articles
of association. Information on where investors can obtain copies of the
memorandum and articles of association is described under the heading `Documents
on Display' under this Item.
Subject to the approval of shareholders at BP's Annual General Meeting to
be held on April 24, 2003, BP proposed to adopt new articles of association to
consolidate amendments which have been necessary to implement legislative
changes since the current articles of association were adopted in 1983.
Objects and Purposes
BP is incorporated under the name BP p.l.c. and is registered in England
and Wales with registered number 102498. Clause 4 of BP's memorandum of
association provides that its objects include the acquisition of petroleum
bearing lands; the carrying on of refining and dealing businesses in the
petroleum, manufacturing, metallurgical or chemicals businesses; the purchase
and operation of ships and all other vehicles and other conveyances; and the
carrying on of any other businesses calculated to benefit BP. The memorandum
grants BP a range of corporate capabilities to effect these objects.
Directors
The business and affairs of BP shall be managed by the directors.
The articles of association place a general prohibition on a director
voting in respect of any contract or arrangement in which he has a material
interest other than by virtue of his interest in shares in the Company. However,
in the absence of some other material interest not indicated below, a director
is entitled to vote and to be counted in a quorum for the purpose of any vote
relating to a resolution concerning the following matters:
-- The giving of security or indemnity with respect to any money lent or
obligation taken by the director at the request or benefit of the
Company;
-- Any proposal in which he is interested concerning the underwriting of
Company securities or debentures;
-- Any proposal concerning any other company in which he is interested,
directly or indirectly (whether as an officer or shareholder or
otherwise) provided that he and persons connected with him are not the
holder or holders of 1% or more of the voting interest in the shares
of such company;
-- Proposals concerning the modification of certain retirement benefits
schemes under which he may benefit and which has been approved by
either the UK Board of Inland Revenue or by the shareholders; and
-- Any proposal concerning the purchase or maintenance of any insurance
policy under which he may benefit.
The UK Companies Act requires a director of a company who is in any way
interested in a contract or proposed contract with the company to declare the
nature of his interest at a meeting of the directors of the company. The
directors may exercise all the powers of the company to borrow money, except
that the amount remaining undischarged of all moneys borrowed by the company
shall not, without approval of the shareholders, exceed the amount paid up on
the share capital plus the aggregate of the amount of the capital and revenue
reserves of the company. Variation of the borrowing power of the board may only
be effected by amending the articles of association.
Page 129
Remuneration of non-executive directors shall be determined in the
aggregate by resolution of the shareholders. Remuneration of executive directors
is determined by the Remuneration Committee. This committee is made up of
non-executive directors only. Any director attaining the age of 70 shall retire
at the next annual general meeting. There is no requirement of share ownership
for a director's qualification.
Dividend Rights; Other Rights to Share in Company Profits; Capital Calls
If recommended by the directors of BP, BP shareholders may, by resolution,
declare dividends but no such dividend may be declared in excess of the amount
recommended by the directors. The directors may also pay interim dividends
without obtaining shareholder approval. No dividend may be paid other than out
of profits available for distribution, as determined under UK GAAP and the UK
Companies Act. Dividends on Ordinary Shares are payable only after payment of
dividends on BP preference shares. Any dividend unclaimed after a period of
twelve years from the date of declaration of such dividend shall be forfeited
and reverts to BP.
Apart from shareholders' rights to share in BP's profits by dividend (if
any is declared), the articles of association provide that the directors may set
aside:
-- a special reserve fund out of the balance of profits each year to make
up any deficit of cumulative dividend on the BP preference shares; and
-- a general reserve out of the balance of profits each year, which shall
be applicable for any purpose to which the profits of the Company may
properly be applied. This may include capitalization of such sum,
pursuant to an ordinary shareholders' resolution, and distribution to
shareholders as if it were distributed by way of a dividend on the
Ordinary Shares or in paying up in full unissued Ordinary Shares for
allotment and distribution as bonus shares.
Any such sums so deposited may be distributed in accordance with the manner
of distribution of dividends as described above.
Holders of shares are not subject to calls on capital by the Company,
provided that the amounts required to be paid on issue have been paid off. All
shares are fully paid.
Voting Rights
The articles of association of BP provide that voting on resolutions at a
shareholders' meeting will be decided on a poll other than resolutions of a
procedural nature, which may be decided on a show of hands. If voting is on a
poll, every shareholder who is present in person or by proxy has one vote for
every Ordinary Share held and two votes for every (pound)5 in nominal amount of
BP preference shares held. If voting is on a show of hands, each shareholder who
is present at the meeting in person or whose duly appointed proxy is present in
person will have one vote, regardless of the number of shares held, unless a
poll is requested. Shareholders do not have cumulative voting rights.
Holders of record of ordinary shares may appoint a proxy, including a
beneficial owner of those shares, to attend, speak and vote on their behalf at
any shareholders' meeting.
Page 130
Record holders of BP ADSs also are entitled to attend, speak and vote at
any shareholders' meeting of BP by the appointment by the approved depositary,
JPMorgan Chase Bank, of them as proxies in respect of the ordinary shares
represented by their ADSs. Each such proxy may also appoint a proxy.
Alternatively, holders of ADSs are entitled to vote by supplying their voting
instructions to the depositary, who will vote the Ordinary Shares represented by
their ADSs in accordance with their instructions.
Proxies may be delivered electronically.
Matters are transacted at shareholders' meetings by the proposing and
passing of resolutions, of which there are three types: ordinary, special or
extraordinary.
An ordinary resolution requires the affirmative vote of a majority of the
votes of those persons voting at a meeting at which there is a quorum. Special
and extraordinary resolutions require the affirmative vote of not less than
three-fourths of the persons voting at a meeting at which there is a quorum. Any
annual general meeting at which it is proposed to put a special or ordinary
resolution requires 21 days' notice. An extraordinary resolution put to the
annual general meeting requires no notice period. Any extraordinary general
meeting at which it is proposed to put a special resolution requires 21 days'
notice; otherwise, the notice period for an extraordinary general meeting is 14
days.
Liquidation Rights; Redemption Provisions
In the event of a liquidation of BP, after payment of all liabilities and
applicable deductions under UK laws and subject to the payment of secured
creditors, the holders of BP preference shares would be entitled to the sum of
(i) the capital paid up on such shares plus, (ii) accrued and unpaid dividends
and (iii) a premium equal to the higher of (a) 10% of the capital paid up on the
BP preference shares and (b) the excess of the average market price over par
value of such shares on the London Stock Exchange during the previous six
months. The remaining assets (if any) would be divided pro rata among the
holders of Ordinary Shares.
Without prejudice to any special rights previously conferred on the holders
of any class of shares, BP may issue any share with such preferred, deferred or
other special rights, or subject to such restrictions as the shareholders by
resolution determine (or, in the absence of any such resolutions, by
determination of the directors), and may issue shares which are to be or may be
redeemed.
Variation of Rights
The rights attached to any class of shares may be varied with the consent
in writing of holders of 75% of the shares of that class or upon the adoption of
an extraordinary resolution passed at a separate meeting of the holders of the
shares of that class. At every such separate meeting, all of the provisions of
the articles of association relating to proceedings at a general meeting apply,
except that the quorum with respect to a meeting to change the rights attached
to the preference shares is 10% or more of the shares of that class, and the
quorum to change the rights attached to the Ordinary Shares is one third or more
of the shares of that class.
Shareholders' Meetings and Notices
Shareholders must provide BP with a postal or electronic address in the UK
in order to be entitled to receive notice of shareholders' meetings. In certain
circumstances, BP may give notices to shareholders by advertisement in UK
newspapers. Holders of BP ADSs are entitled to receive notices under the terms
of the deposit agreement relating to BP ADSs. The substance and timing of
notices is described above under the heading Voting Rights.
Page 131
Under the articles of association, the annual general meeting of
shareholders will be held within 15 months after the preceding annual general
meeting and at a time and place determined by the directors within the United
Kingdom. If any shareholders' meeting is adjourned for lack of quorum, notice of
the time and place of the meeting may be given in any lawful manner, including
electronically. The Chairman has the power to take any action he sees fit to
promote order at any shareholders' meeting.
Limitations on Voting and Shareholding
There are no limitations imposed by English law or BP's memorandum or
articles of association on the right of non-residents or foreign persons to hold
or vote the Company's Ordinary Shares or ADSs, other than limitations that would
generally apply to all of the shareholders.
Disclosure of Interests in Shares
The UK Companies Act permits a public company, on written notice, to
require any person whom the company believes to be or, at any time during the
previous three years prior to the issue of the notice, to have been interested
in its voting shares, to disclose certain information with respect to those
interests. Failure to supply the information required may lead to
disenfranchisement of the relevant shares and a prohibition on their transfer
and receipt of dividends and other payments in respect of those shares. In this
context the term `interest' is widely defined and will generally include an
interest of any kind whatsoever in voting shares, including any interest of a
holder of BP ADSs.
Page 132
MATERIAL CONTRACTS
None.
EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS
There are currently no UK foreign exchange controls or restrictions on
remittances of dividends on the BP ordinary shares or on the conduct of the
Company's operations.
There are no limitations, either under the laws of the UK or under the
articles of association of BP p.l.c., restricting the right of non-resident or
foreign owners to hold or vote BP ordinary or preference shares in the Company.
Page 133
TAXATION
This section describes the material United States federal income tax and UK
taxation consequences of owning ordinary shares or ADSs to a US holder that
holds the ordinary shares or ADSs as capital assets for tax purposes. It does
not apply, however, to members of special classes of holders subject to special
rules and holders that, directly or indirectly, hold 10% or more of the
Company's voting stock.
A US holder is any beneficial owner of Ordinary Shares or ADSs that is (i)
a citizen or resident (for United States federal income tax purposes) of the
United States, (ii) a corporation organized in the United States of any of its
States, (iii) an estate whose income is subject to United States federal income
tax regardless of its source, or (iv) a trust if a United States court can
exercise primary supervision over the trust's administration and one or more
United States persons are authorized to control all substantial decisions of the
trust.
This section is based on the Internal Revenue Code of 1986, as amended, its
legislative history, existing and proposed regulations, published rulings and
court decisions, and the taxation laws of the United Kingdom, all as currently
in effect, as well as on the Convention Between the United States of America and
the United Kingdom entered into force in 1980 (the 'Treaty') and the Convention
Between the United States of America and the United Kingdom which is expected to
enter into force in 2003 (the 'New Treaty'). These laws are subject to change,
possibly on a retroactive basis. This section is further based in part upon the
representations of the Depositary and assumes that each obligation in the
Deposit Agreement and any related agreement will be performed in accordance with
its terms.
For United States federal income tax and UK taxation purposes, a holder of
ADRs evidencing ADSs will be treated as the owner of the Company's ordinary
shares represented by those ADSs. Exchanges of ordinary shares for ADSs, and
ADSs for Ordinary Shares, generally will not be subject to United States federal
income tax or to UK taxation.
Investors should consult their own tax advisor regarding the United States
federal, state and local, the UK and other tax consequences of owning and
disposing of Ordinary Shares and ADSs in their particular circumstances, and in
particular whether they are eligible for the benefits of the Treaty and the New
Treaty.
Taxation of Dividends
United Kingdom Taxation
Under current UK taxation law, no withholding tax will be deducted from
dividends paid by the Company. A shareholder that is a company resident for tax
purposes in the United Kingdom generally will not be taxable on a dividend it
receives from the Company. A shareholder who is an individual resident for tax
purposes in the United Kingdom is entitled to a tax credit on cash dividends
paid on ordinary shares or ADSs of the Company equal to one-ninth of the cash
dividend.
Under the Treaty, a US holder is entitled to a refund from the UK Inland
Revenue equal to the amount of the tax credit available to a shareholder
resident in the United Kingdom (i.e., one-ninth of the dividend received), but
the amount of the dividend plus the amount of the refund are also subject to
withholding in an amount equal to the amount of the tax credit. A US holder
therefore will not receive any payment from the UK Inland Revenue in respect of
a dividend from the Company and will have no further UK tax to pay in respect of
that dividend. Under the Treaty, special rules apply for determining the tax
credit available to a corporation that, either alone or together with one or
more associated corporations, controls, directly or indirectly, 10% or more of
the Company's voting stock.
Page 134
The New Treaty has been ratified by the UK Parliament and was ratified by
the United States Senate on March 13, 2003. Under the New Treaty, a US holder
will not be entitled to a tax refund from the UK Inland Revenue in respect of
dividends in the manner described above. However, dividends received by the US
holder from the Company generally will not be subject to a withholding tax by
the United Kingdom.
The New Treaty generally will be effective in respect of taxes withheld at
source for amounts paid or credited on or after the first day of the second
month after it enters into force. The provisions of the New Treaty affecting all
other US taxes, however, will take effect on January 1, 2004. The rules of the
Treaty will remain applicable until these effective dates. A US holder, however,
may elect to have the Treaty apply in its entirety for a period of twelve months
after the applicable effective dates of the New Treaty.
United States Federal Income Taxation
A US holder must include in gross income as ordinary income the gross
amount of any dividend paid by the Company. A US holder that is eligible for the
benefits of the Treaty may include in the gross amount the UK tax withheld from
the dividend payment pursuant to the Treaty, as described above in 'United
Kingdom Taxation'. Subject to certain limitations, the United Kingdom tax
withheld will be creditable against the US holder's United States federal income
tax liability, if the US holder is eligible for the benefits of the Treaty and
has appropriately filed Internal Revenue Form 8833.
A US holder will not be entitled to a UK tax credit under the New Treaty,
but also will not be subject to UK withholding tax. In that case, the US holder
will include in income for United States federal income tax purposes only the
amount of the dividend actually received from the Company, and the receipt of a
dividend will not entitle the US holder to a foreign tax credit.
In either case, the dividend must be included in income when the US holder,
in the case of Ordinary Shares, or the Depositary, in the case of ADSs, actually
or constructively receives the dividend, and will not be eligible for the
dividends-received deduction generally allowed to United States corporations in
respect of dividends received from other United States corporations. Dividends
will be income from sources outside the United States, and generally will be
'passive income' or 'financial services income', which is treated separately
from other types of income for purposes of computing the allowable foreign tax
credit.
If a US holder holds ordinary shares of the Company, the amount of the
dividend distribution on the ordinary shares that is paid in pounds sterling
will be the US dollar value of the pounds sterling payments made, determined at
the spot pounds sterling/US dollar rate on the date the dividend distribution is
includable in income, regardless of whether the payment is in fact converted
into US dollars. Generally, any gain or loss resulting from currency exchange
fluctuations during the period from the date the pounds sterling dividend
payment is includible in income to the date the payment is converted into US
dollars will be treated as ordinary income or loss. The gain or loss generally
will be income or loss from sources within the United States for foreign tax
credit limitation purposes.
Taxation of Capital Gains
United Kingdom Taxation
A US holder may be liable for both United Kingdom and United States tax in
respect of a gain on the disposal of Ordinary Shares or ADSs if the US holder is
(i) a citizen of the United States resident or ordinarily resident in the United
Kingdom, (ii) a United States domestic corporation resident in the United
Kingdom by reason of its business being managed or controlled in the United
Kingdom or (iii) a citizen of the United States or a corporation that carries on
a trade or profession or vocation in the United Kingdom through a branch or
agency or, in respect of corporations for accounting periods beginning on or
after January 1, 2003, through a permanent establishment, and that have used,
held, or acquired the ordinary shares or ADSs for the purposes of such trade,
profession or vocation of such branch, agency or permanent establishment.
However, subject to applicable limitations and provisions of the Treaty, such
persons may be entitled to a tax credit against their United States federal
income tax liability for the amount of United Kingdom capital gains tax or UK
corporation tax on chargeable gains (as the case may be) which is paid in
respect of such gain.
Page 135
Under the New Treaty, capital gains on dispositions of Ordinary Shares or
ADSs generally will be subject to tax only in the jurisdiction of residence of
the relevant holder as determined under both the laws of the United Kingdom and
the United States and as required by the terms of the New Treaty.
Under the New Treaty, individuals who are residents of either the United
Kingdom or the United States and who have been residents of the other
jurisdiction (the United States or the United Kingdom, as the case may be) at
any time during the six years immediately preceding the relevant disposal of
ordinary shares or ADRs may be subject to tax with respect to capital gains
arising from a disposition of Ordinary Shares or ADSs of the Company not only in
the jurisdiction of which the holder is resident at the time of the disposition,
but also in the other jurisdiction.
United States Federal Income Taxation
A US holder that sells or otherwise disposes of ordinary shares or ADSs
will recognize a capital gain or loss for United States federal income tax
purposes equal to the difference between the US dollar value of the amount
realized and the holder's tax basis, determined in US dollars, in the ordinary
shares or ADSs. A capital gain of a noncorporate US holder is generally taxed at
a maximum rate of 20% where the property is held more than one year. The gain or
loss will generally be income or loss from sources within the United States for
foreign tax credit limitation purposes. The deductibility of capital losses is
subject to limitations.
Additional Tax Considerations
UK Inheritance Tax
The US-UK double taxation convention relating to estate and gift taxes (the
Estate Tax Convention) applies to inheritance tax. ADRs held by an individual
who is domiciled for the purposes of the Estate Tax Convention in the USA and is
not for the purposes of the Estate Tax Convention a national of the UK will not
be subject to inheritance tax on death or on transfer during the individual's
lifetime unless, among other things, the ADSs are part of the business property
of a permanent establishment situated in the UK or pertain to a fixed base
situated in the UK used for the performance of independent personal services. In
the exceptional case where ADSs are subject both to inheritance tax and to US
Federal gift or estate tax, the Estate Tax Convention generally provides for tax
paid in the UK to be credited against tax payable in the USA or for tax paid in
the USA to be credited against tax payable in the UK based on priority rules set
forth in the Estate Tax Convention.
UK Stamp Duty and Stamp Duty Reserve Tax
The statements below relate to what is understood to be the current
practice of the UK Inland Revenue under existing law.
Provided that the instrument of transfer is not executed in the UK and
remains at all times outside the UK, and the transfer does not relate to any
matter or thing done or to be done in the UK, no UK stamp duty is payable on the
acquisition or transfer of ADSs. Neither will an agreement to transfer ADSs in
the form of ADRs give rise to a liability to stamp duty reserve tax.
Page 136
Purchases of BP ordinary shares, as opposed to ADSs, through the CREST
system of paperless share transfers will be subject to stamp duty reserve tax at
a rate of 0.5%. The charge will arise as soon as there is an agreement for the
transfer of the shares (or, in the case of a conditional agreement, when the
condition is fulfilled). The stamp duty reserve tax will apply to agreements to
transfer 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 (pound)100 (or part), or
stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are
generally the liability of the purchaser. A subsequent transfer of BP ordinary
shares to the Depositary's nominee will give rise to further stamp duty at the
rate of (pound)1.50 per (pound)100 (or part) or stamp duty reserve tax at the
rate of 1.5% of the value of the 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 (pound)5 per transfer.
An ADR holder electing to receive ADSs instead of a cash dividend will be
responsible for the stamp duty reserve tax due on issue of shares to the
Depositary's nominee and calculated at the rate of 1.5% on the issue price of
the shares. Current UK Inland Revenue practice is to calculate the issue price
by reference to the total cash receipt (i.e. cash dividend plus the Refund if
any) to which a US Holder would have been entitled had the election to receive
ADSs instead of a cash dividend not been made. ADR holders electing to receive
ADSs instead of the cash dividend authorize the Depositary to sell sufficient
shares to cover this liability.
DOCUMENTS ON DISPLAY
It is possible to read and copy documents referred to in this annual report
on Form 20-F that have been filed with the SEC at the SEC's public reference
room located at 450 Fifth Street, NW, Washington, DC 20549 and at the SEC's
other public reference rooms in New York City and Chicago. Please call the SEC
at 1-800-SEC-0330 for further information on the public reference rooms and
their copy charges. The SEC filings are also available to the public from
commercial document retrieval services and, for most recent BP periodic filings
only, at the Internet world wide web site maintained by the SEC at www.sec.gov.
Page 137
ITEM 11 -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
BP is exposed to a number of different market risks arising from the
Group's normal business activities. Market risk is the possibility that changes
in currency exchange rates, interest rates or oil and natural gas prices will
adversely affect the value of the Group's financial assets, liabilities or
expected future cash flows. The Group has developed policies aimed at managing
the volatility inherent in certain of these natural business exposures and in
accordance with these policies the Group enters into various transactions using
derivative financial and commodity instruments (derivatives). Derivatives are
contracts whose value is derived from one or more underlying financial
instruments, indices or prices which are defined in the contract. The Group also
trades derivatives in conjunction with these risk management activities.
In market risk management and trading, conventional exchange-traded
derivative instruments such as futures and options are used, as well as
non-exchange-traded instruments such as swaps, `over-the-counter' 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 derivative activity, whether for risk management or trading, is carried
out by specialist teams that have the appropriate skills, experience and
supervision. These teams are subject to close financial and management control,
meeting generally accepted industry practice and reflecting the principles of
the Group of Thirty Global Derivatives Study recommendations. A Trading Risk
Management Committee has oversight of the quality of internal control in the
Group's trading function. Independent control functions monitor compliance with
BP's policies. The control framework includes prescribed trading limits that are
reviewed regularly by senior management, daily monitoring of risk exposure using
value-at-risk principles, marking trading exposures to market and stress testing
to assess the exposure to potentially extreme market situations. The Group's
supply and trading activities in oil, natural gas and financial markets are
managed within a single integrated function. This has the responsibility for
ensuring high and consistent standards of control, making investments in the
necessary systems and supporting infrastructure and providing professional
management oversight.
Further information about BP's use of derivatives, their characteristics,
and the accounting treatment thereof is given in Item 18 -- Financial Statements
-- Note 1 and Note 26.
The Group's accounting policies under UK GAAP do not satisfy the criteria
for hedge accounting under Statement of Financial Accounting Standards No. 133
`Accounting for Derivative Instruments and Hedging Activities'. The Group does
not intend to modify its practice under UK GAAP. See Item 18 -- Financial
Statements -- Note 50 for further information.
Risk Management
Foreign Currency Exchange Rate Risk
Fluctuations in exchange rates can have significant effects on the Group's
reported results. The effects of most exchange rate fluctuations are absorbed in
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.
Page 138
The main underlying economic currency of the Group's cash flows is the US
dollar. This is because BP's major product, oil, is priced internationally in US
dollars. BP's foreign exchange management policy is to minimize economic and
material transactional exposures arising 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 risks, and then dealing with any material residual foreign exchange
risks. Significant residual non-US dollar exposures are managed using a range of
derivatives. The most significant of such exposures are the sterling-based
capital leases, the net Euro cash inflows mainly relating to downstream and
chemicals in Europe, the sterling cash flow requirements for UK Corporation Tax,
and the capital expenditure and operational requirements of Exploration and
Production, mainly in the UK. In addition, most of the Group's borrowings are in
US dollars or are hedged with respect to the US dollar. At December 31, 2002,
the total of foreign currency borrowings not swapped into US dollars amounted to
$903 million. The principal elements of this are $103 million of borrowings in
sterling, $74 million in Malaysian ringgits, $77 million in Trinidad and Tobago
dollars and $474 million in Euros.
The following table provides 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/US dollar, euro/US dollar and Norwegian
krone/US dollar exchange rates. Where foreign currency denominated borrowings
are swapped into US dollars using forwards or cross currency swaps such that
currency risk is completely eliminated, neither the borrowing nor the derivative
are included in the table.
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 forwards relate to sterling-based capital leases which effectively
convert the lease obligation from sterling into dollars. The euro forwards
relate mainly to payments for capital and operational expenditure. The Norwegian
krone forwards relate to the Group's Norwegian tax payments over the next year.
The fair value represents an estimate of the gain or loss which would be
realized if the contracts were settled at the balance sheet date.
For cylinders, the tables present the notional amounts of the constituent
purchased call and written put option contracts at December 31, 2002 and the
weighted average strike rates. The receive sterling cylinders relate to the
Group's expected sterling tax payments and net operational expenditures over the
next year. The pay Euro cylinders relate to the Group's expected net Euro cash
inflows from operations and the sale of business assets.
Page 139
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.
Notional amount by expected maturity date
---------------------------------------------
Fair value
asset/
2003 2004 2005 2006 2007 Total (liability)
------ ------ ------ ------ ------ ------ ----------
($ million)
At December 31, 2002
Forwards
Receive sterling/pay US dollars
Contract amount...................... 2,066 30 -- -- -- 2,096 177
Weighted average contractual
exchange rate....................... 1.48
Receive euro/pay US dollars
Contract amount...................... (3) 47 14 -- -- 58 43
Weighted average contractual
exchange rate....................... 0.96
Receive Norwegian krone/pay US dollars
Contract amount...................... 204 5 2 -- -- 211 15
Weighted average contractual
exchange rate (a).................. 8.58
Cylinders
Receive sterling/pay US dollars
Purchased call
Contract amount....................... 859 -- -- -- -- 859 10
Weighted average strike price......... 1.62
Sold put
Contract amount....................... 859 -- -- -- -- 859 (4)
Weighted average strike price......... 1.52
Pay euro/receive US dollars
Sold call
Contract amount....................... 430 -- -- -- -- 430 (11)
Weighted average strike price......... 1.05
Purchased put
Contract amount....................... 430 -- -- -- -- 430 1
Weighted average strike price......... 0.92
Pay euro/receive sterling
Sold call
Contract amount....................... 614 -- -- -- -- 614 (3)
Weighted average strike price.......(pound) 0.68
Purchased put
Contract amount....................... 614 -- -- -- -- 614 1
Weighted average strike price.......(pound) 0.62
Page 140
Notional amount by expected maturity date
-----------------------------------------
Fair value
asset/
2002 2003 2004 2005 2006 Total (liability)
------ ------ ------ ------ ------ ------ --------
($ million)
At December 31, 2001
Forwards
Receive sterling/pay US dollars
Contract amount...................... 3,822 (48) -- -- -- 3,774 18
Weighted average contractual
exchange rate...................... 1.44
Receive euro/pay US dollars
Contract amount...................... 1,055 190 55 13 1 1,314 (20)
Weighted average contractual
exchange rate...................... 0.90
Receive Norwegian krone/pay US dollars
Contract amount...................... 172 6 2 1 -- 181 1
Weighted average contractual
exchange rate (a).................. 9.49
---------------
(a) Weighted average contractual exchange rates are expressed as US dollars per
non-US dollar currency unit except Norwegian krone which are expressed as
krone per US dollar.
Interest Rate Risk
BP is exposed to interest rate risk on short- and long-term floating rate
instruments and as a result of the refinancing of fixed rate finance debt.
Consequently, as well as managing the currency and the maturity of debt, the
Group manages interest expense through the balance between generally lower-cost
floating rate debt, which has inherently higher risk, and generally more
expensive but lower-risk, fixed rate debt. The Group is exposed predominantly to
US dollar LIBOR interest rates as borrowings are mainly denominated in, or
swapped into, US dollars. The Group uses derivatives to achieve the required mix
between fixed and floating rate debt. During 2002, the proportion of floating
rate debt was in the range of 41-60% of total net debt outstanding.
The following table shows, by major currency, the Group's finance debt at
December 31, 2002 and 2001 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.
Fixed rate debt Floating rate debt
------------------------------------ ----------------------
Weighted Weighted Weighted
average average time average
interest for which interest
rate rate is fixed Amount rate Amount Total
-------- -------- -------- -------- -------- --------
(%) (years) ($ million) (%) ($ million) ($ million)
At December 31, 2002
US dollar........................... 7 7 7,818 2 13,287 21,105
Sterling............................ -- -- -- 4 103 103
Other currencies.................... 7 11 317 5 483 800
-------- -------- --------
Total loans......................... 8,135 13,873 22,008
======== ======== ========
At December 31, 2001
US dollar........................... 7 8 11,603 2 9,365 20,968
Sterling............................ -- -- -- 4 133 133
Other currencies.................... 10 29 122 6 194 316
-------- -------- --------
Total loans......................... 11,725 9,692 21,417
======== ======== ========
Page 141
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, 2002. 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, 2003, the Group's 2003 earnings before taxes would
decrease by approximately $130 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, 2002 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.
Oil Price Risk
The Group's risk management policy with respect to oil price risk is to
manage only those exposures associated with the immediate operational programme
for certain of its equity share of production and certain of its refinery and
marketing activities. To this end, BP's supply and trading function 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. 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.
High Low Average December 31
------ ------ ------- ------------
($ million)
2002
Oil price contracts.......................... 13 11 12 11
2001
Oil price contracts.......................... 11 4 7 7
2000
Oil price contracts.......................... 18 11 15 11
Natural Gas Price Risk
BP's general policy with respect to natural gas price risk is to manage
only a portion of its exposure to price fluctuations. Natural gas swaps, options
and futures are used to convert specific sales and purchases contracts from
fixed prices to market prices. Swaps are also used to hedge exposure to price
differentials between locations.
Page 142
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 fixed
price and the year-end forward price related to the settlement month for swaps.
At December 31, 2002, in addition to the swaps contracts shown in the table
there were options contracts with aggregate notional amounts of $11 million
($1,090 million at December 31, 2001) and terms of up to one year.
Page 143
Weighted
Fair value average price
Contract ------------------ ------------------
Quantity amount Asset Liability Receive Pay
------- ------- ------- ------- ------- -------
(Btu trillion)(a) ($ million) ($ million) ($ per mmbtu)(b)
At December 31, 2002
Maturing in 2003
Swaps
Receive variable/pay fixed............ 190 734 129 (4) 4.54 3.89
Receive fixed/pay variable............ 140 529 -- (108) 3.78 4.56
Receive and pay variable.............. 586 2,633 62 (61) 4.40 4.40
Maturing in 2004
Swaps
Receive variable/pay fixed............ 24 95 8 (1) 4.20 3.87
Receive fixed/pay variable............ 16 62 -- (9) 3.76 4.33
Receive and pay variable.............. 181 757 19 (22) 4.06 4.08
Maturing in 2005
Swaps
Receive variable/pay fixed............ 6 25 1 -- 3.91 3.78
Receive fixed/pay variable............ 1 6 -- -- 3.74 3.83
Receive and pay variable.............. 115 444 10 (10) 3.77 3.77
Maturing in 2006
Swaps
Receive variable/pay fixed............ 2 7 -- -- 3.85 3.94
Receive fixed/pay variable............ -- 1 -- -- 4.32 3.85
Receive and pay variable.............. 61 228 1 (3) 3.62 3.70
Maturing in 2007
Swaps
Receive variable/pay fixed............ 2 7 -- -- 3.91 3.99
Receive fixed/pay variable............ -- 1 -- -- 4.36 3.91
Receive and pay variable.............. 55 204 1 (3) 3.70 3.75
Maturing beyond 2007
Swaps
Receive variable/pay fixed............ 1 5 -- -- 3.93 4.05
Receive fixed/pay variable............ 1 5 1 -- 4.85 4.13
Receive and pay variable.............. 119 461 1 (5) 3.81 3.85
At December 31, 2001
Maturing in 2002
Swaps
Receive variable/pay fixed............ 447 1,600 17 (419) 2.64 3.58
Receive fixed/pay variable............ 302 1,002 210 (27) 3.32 2.64
Receive and pay variable.............. 4,232 44 653 (610) 2.68 2.68
Maturing in 2003
Swaps
Receive variable/pay fixed............ 104 349 37 (47) 3.24 3.36
Receive fixed/pay variable............ 86 272 25 (32) 3.16 3.21
Receive and pay variable.............. 682 4 52 (55) 2.99 3.00
Maturing in 2004
Swaps
Receive variable/pay fixed............ 20 63 11 (6) 3.45 3.18
Receive fixed/pay variable............ 8 20 4 (10) 2.54 3.30
Receive and pay variable.............. 230 7 18 (25) 2.90 2.93
Maturing in 2005
Swaps
Receive variable/pay fixed............ 3 8 2 (1) 3.43 3.02
Receive fixed/pay variable............ 4 11 2 (4) 2.89 3.37
Receive and pay variable.............. 165 8 12 (20) 3.02 3.07
Maturing in 2006
Swaps
Receive variable/pay fixed............ 2 7 -- (1) 3.49 3.94
Receive fixed/pay variable............ 3 10 2 (2) 3.42 3.45
Receive and pay variable.............. 102 9 5 (14) 3.10 3.19
Maturing beyond 2006
Swaps
Receive variable/pay fixed............ 3 12 -- (1) 3.59 4.02
Received fixed/pay variable........... 13 43 5 (10) 3.26 3.68
Receive and pay variable.............. 318 25 22 (48) 2.79 2.87
---------------
(a) British thermal units (btu)
(b) Million british thermal units (mmbtu)
Page 144
Trading
In conjunction with the risk management activities discussed above, BP also
trades interest rate and foreign currency exchange rate derivatives. The Group
controls the scale of the trading exposures by using a value at risk model with
a maximum value at risk limit authorized by the board.
In addition to the risk management activities related to equity crude
disposal, refinery supply and marketing, BP's supply and trading function
undertakes trading in the full range of conventional derivative financial and
commodity instruments and physical cargoes available in the energy markets. The
Group also uses financial and commodity derivatives to manage certain of its
exposures to price fluctuations on natural gas transactions. These activities
are monitored and are 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 value-at-risk techniques. These
techniques are based on a variance/covariance model or a Monte Carlo simulation
and make a statistical assessment of the market risk arising from possible
future changes in market values over a 24-hour period. The calculation of the
range of potential changes in fair value takes into account a snapshot of the
end-of-day exposures, and the history of one-day price movements over the
previous twelve months, together with the correlation of these price movements.
The potential movement in fair values is expressed to three standard deviations
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 models take account of derivative financial instruments such as
interest rate forward and futures contracts and swap agreements; foreign
exchange forward and futures contracts and swap agreements; and oil and natural
gas price futures and swap agreements. Financial assets and liabilities and
physical crude oil and refined products that are treated as trading positions
are also included in these calculations. For options a linear approximation is
included in the value-at-risk models. The value-at-risk calculation for oil and
natural gas price exposure also includes derivative commodity instruments
(commodity contracts that permit settlement either by delivery of the underlying
commodity or in cash), such as forward contracts.
The following table shows values at risk for trading activities.
High Low Average December 31
------ ------ ------- ------------
($ million)
2002
Interest rate trading........................ -- -- -- --
Foreign exchange trading..................... 2 -- 1 --
Oil price trading............................ 34 14 23 19
Natural gas price trading.................... 18 1 6 9
2001
Interest rate trading........................ 1 -- -- --
Foreign exchange trading..................... 3 -- 1 --
Oil price trading............................ 29 10 18 17
Natural gas price trading.................... 21 4 10 9
2000
Interest rate trading........................ 2 -- 1 --
Foreign exchange trading..................... 15 -- 1 1
Oil price trading............................ 23 4 13 13
Natural gas price trading.................... 16 1 6 13
Page 145
The following tables shows the changes during the year in the net fair
value of instruments held for trading purposes.
Fair value Fair value Fair value Fair value
interest exchange oil natural gas
rate rate price price
contracts contracts contracts contracts
--------- --------- --------- ----------
($ million)
Fair value of contracts at January 1, 2002........... -- (3) 26 12
Contracts realized or settled in the year............ -- 3 (22) 154
Fair value of new contracts when entered
into during the year............................... -- -- -- --
Changes in fair value attributable to changes
in valuation techniques and assumptions............ -- -- -- --
Other changes in fair values......................... -- 12 18 (9)
--------- --------- --------- ----------
Fair value of contracts at December 31, 2002......... -- 12 22 157
========= ========= ========= ==========
The following table shows the net fair value of contracts held for trading
purposes at December 31, 2002 analyzed by maturity period and by methodology of
fair value estimation.
Fair value of contracts at December 31, 2002
-----------------------------------------------------
Maturity Maturity Total
less than Maturity Maturity over fair
1 year 1-3 years 4-5 years 5 years value
-------- -------- -------- -------- -------
($ million)
Prices actively quoted................................. 116 66 6 -- 188
Prices provided by other external sources.............. (10) 2 -- -- (8)
Prices based on models and other
valuation methods.................................... 11 -- -- -- 11
------ ------ ------ ------ ------
117 68 6 -- 191
====== ====== ====== ====== ======
ITEM 12 -- DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
Not applicable
Page 146
PART II
ITEM 13 -- DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
None.
ITEM 14 -- MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF
PROCEEDS
None.
ITEM 15 -- CONTROLS AND PROCEDURES
Under the supervision and with the participation of the Company's
management, including the Company's Chief Executive Officer and Chief Financial
Officer, the Company has evaluated the effectiveness of the design and operation
of its disclosure controls and procedures pursuant to Exchange Act Rule
13a-14(c) within 90 days of the filing date of this annual report. Based on that
evaluation, the Chief Executive Officer and Chief Financial Officer have
concluded that these disclosure controls and procedures are effective.
In designing and evaluating our disclosure controls and procedures, our
management, including the Chief Executive Officer and Chief Financial Officer,
recognized that any controls and procedures, no matter how well designed and
operated, can provide only reasonable assurance of achieving the desired control
objectives, and our management necessarily was required to apply its judgement
in evaluating the cost-benefit relationship of possible controls and procedures.
Because of the inherent limitations in all control systems, no evaluation of
controls can provide absolute assurance that all control issues and instances of
fraud, if any, within the Company have been detected.
There were no significant changes in the Company's internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of their most recent evaluation.
Page 147
PART III
ITEM 17 -- FINANCIAL STATEMENTS
Not applicable.
ITEM 18 -- FINANCIAL STATEMENTS
(a) Financial Statements
The following financial statements, together with the reports of the
Independent Auditors thereon, are filed as part of this annual report:
Page
Report of Independent Auditors and Consent of Independent Auditors............................. F-1
Consolidated Statement of Income for the Years Ended December 31, 2002, 2001, and 2000......... F-2
Consolidated Balance Sheet at December 31, 2002 and 2001....................................... F-3
Consolidated Statement of Cash Flows for the Years
Ended December 31, 2002, 2001, and 2000...................................................... F-4
Statement of Total Recognized Gains and Losses for the Years
Ended December 31, 2002, 2001, and 2000...................................................... F-5
Statement of Changes in BP Shareholders' Interest for
the Years Ended December 31, 2002, 2001, and 2000............................................ F-6
Notes to Financial Statements.................................................................. F-9
Supplementary Oil and Gas Information (Unaudited).............................................. F-127
Schedule for the Years Ended December 31, 2002, 2001, and 2000
Schedule II Valuation and Qualifying Accounts................................................ S-1
ITEM 19 -- EXHIBITS
The following documents are filed as part of, or furnished with, this
annual report:
Exhibit 1 Memorandum and Articles of Association of BP p.l.c.*
Exhibit 4.1 The BP Executive Directors' Long Term Incentive Plan+
Exhibit 4.2 Directors' Service Contracts
Exhibit 7 Computation of Ratio of Earnings to Fixed Charges (Unaudited)
Exhibit 8 Subsidiaries
Exhibit 10 Section 906 Certifications**
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 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.
* Incorporated by reference to the Company's Annual Report on Form 20-F for
the year ended December 31, 2001.
** Furnished, not filed.
+ Incorporated by reference to the Company's Annual Report on Form 20-F for
the year ended December 31, 2000.
Page 148
BP p.l.c. AND SUBSIDIARIES
REPORT OF INDEPENDENT AUDITORS
To: The Board of Directors
BP p.l.c.
We have audited the accompanying consolidated balance sheets of BP p.l.c.
as of December 31, 2002 and 2001, and the related consolidated statements of
income, changes in BP shareholders' interest, total recognized gains and losses,
and cash flows for each of the three years in the period ended December 31,
2002. Our audits also included the financial statement schedule listed in the
Index at Item 18. These financial statements and schedule are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements and schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United Kingdom and United States. Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the consolidated financial position of
BP p.l.c. at December 31, 2002 and 2001, and the consolidated results of its
operations and its consolidated cash flows for each of the three years in the
period ended December 31, 2002, 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 50 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.
As discussed in Note 45 of Notes to Financial Statements, in the year ended
December 31, 2002 the Company changed its method of accounting for deferred
taxation.
/s/ ERNST & YOUNG LLP
-----------------------
London, England Ernst & Young LLP
February 11, 2003
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference of our report dated February
11, 2003, with respect to the consolidated financial statements of BP p.l.c.
included in this Annual Report (Form 20-F) for the year ended December 31, 2002
in the following Registration Statements:
Registration Statements on Form F-3 (File Nos. 333-9790 and 333-65996) of
BP p.l.c.;
Registration Statement on Form F-3 (File No. 333-83180) of BP Australia
Capital Markets Limited, BP Canada Finance Company, BP Capital Markets p.l.c.,
BP Capital Markets America Inc. and BP p.l.c.; and
Registration Statements on Form S-8 (File Nos. 33-21868, 333-9020,
333-9798, 333-79399, 333-34968, 333-67206, 333-74414 and 333-102583, 333-103923
and 333-103924) of BP p.l.c.
/s/ ERNST & YOUNG LLP
-----------------------
London, England Ernst & Young LLP
March 24, 2003
F - 1
BP p.l.c. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
Years ended December 31,
---------------------------------
Note 2002 2001 2000
---- ------- ------- -------
($ million, except per share amounts)
Turnover.................................................. 180,186 175,389 161,826
Less: Joint ventures...................................... 1,465 1,171 13,764
------- ------- -------
Group turnover............................................ 178,721 174,218 148,062
Replacement cost of sales................................. 155,528 147,001 120,797
Production taxes.......................................... 3 1,274 1,689 2,061
------- ------- -------
Gross profit.............................................. 21,919 25,528 25,204
Distribution and administration expenses.................. 4 12,632 10,918 9,331
Exploration expense....................................... 644 480 599
------- ------- -------
8,643 14,130 15,274
Other income.............................................. 5 641 694 805
------- ------- -------
Group replacement cost operating profit................... 9,284 14,824 16,079
Share of profits of joint ventures........................ 346 443 808
Share of profits of associated undertakings............... 616 760 792
------- ------- -------
Total replacement cost operating profit................... 10,246 16,027 17,679
Profit (loss) on sale of businesses or termination
of operations........................................... 7 (33) (68) 132
Profit (loss) on sale of fixed assets..................... 7 1,201 603 88
------- ------- -------
Replacement cost profit before interest and tax........... 11,414 16,562 17,899
Inventory holding gains (losses).......................... 1,129 (1,900) 728
------- ------- -------
Historical cost profit before interest and tax............ 12,543 14,662 18,627
Interest expense.......................................... 8 1,279 1,670 1,770
------- ------- -------
Profit before taxation.................................... 11,264 12,992 16,857
Taxation.................................................. 13 4,342 6,375 6,648
------- ------- -------
Profit after taxation..................................... 6,922 6,617 10,209
Minority shareholders' interest........................... 77 61 89
------- ------- -------
Profit for the year*...................................... 6,845 6,556 10,120
Dividend requirements on preference shares*............... 2 2 2
------- ------- -------
Profit for the year applicable to ordinary shares*........ 6,843 6,554 10,118
------- ------- -------
Profit per ordinary share - cents
Basic..................................................... 16 30.55 29.21 46.77
Diluted................................................... 16 30.41 29.04 46.46
======= ======= =======
Dividends per ordinary share - cents...................... 15 24.00 22.00 20.50
======= ======= =======
Average number outstanding of 25 cents ordinary shares
(in thousands).......................................... 22,397,126 22,435,737 21,638,280
========== ========== ==========
----------
* 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 50.
The Notes to Financial Statements are an integral part of this Statement.
F - 2
BP p.l.c. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
December 31,
--------------------------------------------
Note 2002 2001
------ ---------------- ----------------
($ million)
Fixed assets
Intangible assets............................. 20 15,566 16,489
Tangible assets............................... 21 87,682 77,410
Investments
Joint ventures
Gross assets................................ 4,829 4,661
Gross liabilities........................... 798 800
------- -------
Net investment.............................. 22 4,031 3,861
Associated undertakings...................... 22 4,626 5,433
Other........................................ 22 2,154 2,669
------- -------
10,811 11,963
------- -------
Total fixed assets............................... 114,059 105,862
Current assets
Inventories................................... 23 10,181 7,631
Trade receivables............................. 24 18,798 15,436
Other receivables falling due
Within one year.............................. 24 8,107 6,552
After more than one year..................... 24 6,245 4,681
Investments................................... 25 215 450
Cash at bank and in hand...................... 1,520 1,358
------- -------
45,066 36,108
------- -------
Current liabilities -- falling due within one year
Finance debt.................................. 29 10,086 9,090
Trade payables................................ 30 17,454 13,129
Other accounts payable and accrued liabilities 30 18,761 15,395
------- -------
46,301 37,614
------- -------
Net current assets (liabilities)................. (1,235) (1,506)
------- -------
Total assets less current liabilities............ 112,824 104,356
Noncurrent liabilities
Finance debt.................................. 29 11,922 12,327
Accounts payable and accrued liabilities...... 30 3,455 3,086
Provisions for liabilities and charges
Deferred taxation............................. 13 13,514 11,702
Other......................................... 31 13,886 11,482
------- -------
42,777 38,597
------- -------
Net assets....................................... 70,047 65,759
Minority shareholders' interest -- equity........ 638 598
------- -------
BP shareholders' interest*....................... 69,409 65,161
======= =======
Represented by:
Capital shares
Preference.................................... 21 21
Ordinary...................................... 5,595 5,608
Paid in surplus.................................. 32 4,243 4,014
Merger reserve................................... 32 27,033 26,983
Other reserves................................... 32 173 223
Retained earnings................................ 32/33 32,344 28,312
------- -------
69,409 65,161
======= =======
----------
* A summary of the adjustments to BP shareholders' interest which would be
required if generally accepted accounting principles in the United States
had been applied instead of those generally accepted in the United Kingdom
is given in Note 50.
The Notes to Financial Statements are an integral part of this Balance Sheet.
F - 3
BP p.l.c. AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS
Years ended December 31,
-------------------------------
Note 2002 2001 2000
----- -------- -------- ---------
($ million)
Net cash inflow from operating activities.................. 34 19,342 22,409 20,416
------ ------ ------
Dividends from joint ventures.............................. 198 104 645
------ ------ ------
Dividends from associated undertakings..................... 368 528 394
------ ------ ------
Servicing of finance and returns on investments
Interest received.......................................... 231 256 444
Interest paid.............................................. (1,204) (1,282) (1,354)
Dividends received......................................... 102 132 42
Dividends paid to minority shareholders.................... (40) (54) (24)
------ ------ ------
Net cash outflow from servicing of finance and
returns on investments................................... (911) (948) (892)
------ ------ ------
Taxation
UK corporation tax......................................... (979) (1,058) (869)
Overseas tax............................................... (2,115) (3,602) (5,329)
------ ------ ------
Tax paid................................................... (3,094) (4,660) (6,198)
------ ------ ------
Capital expenditure and financial investment
Payments for tangible and intangible fixed assets.......... (12,049) (12,142) (8,837)
Payments for fixed assets - investments.................... (67) (72) (1,264)
Proceeds from the sale of fixed assets..................... 19 2,470 2,365 3,029
------ ------ ------
Net cash outflow for capital expenditure
and financial investment................................. (9,646) (9,849) (7,072)
------ ------ ------
Acquisitions and disposals
Investments in associated undertakings..................... (971) (586) (985)
Proceeds from sale of investment in Ruhrgas................ 19 2,338 -- --
Acquisitions, net of cash acquired......................... (4,324) (1,210) (6,265)
Net investment in joint ventures........................... (354) (497) (218)
Proceeds from the sale of businesses....................... 19 1,974 538 8,333
------ ------ ------
Net cash (outflow) inflow for acquisitions and disposals... (1,337) (1,755) 865
------ ------ ------
Equity dividends paid...................................... (5,264) (4,827) (4,415)
------ ------ ------
Net cash (outflow) inflow.................................. (344) 1,002 3,743
====== ====== ======
Financing.................................................. 34 (181) 972 3,413
Management of liquid resources............................. 34 (220) (211) 452
Increase (decrease) in cash................................ 34 57 241 (122)
------ ------ ------
(344) 1,002 3,743
====== ====== ======
---------------
For a cash flow statement and a statement of comprehensive income prepared on
the basis of US GAAP see Note 50 -- US generally accepted accounting principles.
The Notes to Financial Statements are an integral part of these Statements.
F - 4
BP p.l.c. AND SUBSIDIARIES
STATEMENT OF TOTAL RECOGNIZED GAINS AND LOSSES
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Profit for the year.............................................. 6,845 6,556 10,120
Currency translation differences (net of tax).................... 3,333 (828) (2,340)
-------- -------- ---------
Total recognized gains and losses relating to the year........... 10,178 5,728 7,780
======== =========
Prior year adjustment-- change in accounting policy.............. (9,206)
--------
Total recognized gains and losses since last annual accounts..... 972
========
The Notes to Financial Statements are an integral part of these Statements.
F - 5
BP p.l.c. AND SUBSIDIARIES
STATEMENT OF CHANGES IN BP SHAREHOLDERS' INTEREST
The Company's authorized ordinary share capital at December 31, 2002, 2001
and 2000 was 36 billion shares of 25 cents each, amounting to $9 billion. In
addition the Company has authorized preference share capital of 12,750,000
shares of (pound)1 each ($21 million). Details of movements in share capital are
shown in Note 32.
The allotted, called up and fully paid share capital at December 31, was as
follows:
Shares
------------------------
Authorized Issued Amount
------------ --------- ---------
($ million)
Non-equity-- preference shares
8% cumulative first preference
shares of(pound)1 each at December 31, 2002, 2001 and 2000........ 7,250,000 7,232,838 12
============= ========= =========
9% cumulative second preference
shares of(pound)1 each at December 31, 2002, 2001 and 2000........ 5,500,000 5,473,414 9
============= ========= =========
Equity -- ordinary shares of 25 cents each
Authorized
December 31, 2002, 2001 and 2000.................................... 36,000,000,000
==============
Years ended December 31,
--------------------------------------------------------------------------
2002 2001 2000
----------------------- ---------------------- ---------------------
Shares of Shares of Shares of
25 cents 25 cents 25 cents
Issued each Amount each Amount each Amount
--------- --------- --------- --------- --------- ---------
(thousands) ($ million) (thousands) ($ million) (thousands) ($ million)
January 1...................... 22,432,077 5,608 22,528,747 5,632 19,484,024 4,871
Employee share schemes (a)..... 33,821 9 33,461 8 38,112 9
ARCO (b)....................... 12,894 3 23,798 7 -- --
ARCO acquisition............... -- -- -- -- 3,228,274 807
Repurchase of ordinary
share capital (c)............ (100,141) (25) (153,929) (39) (221,663) (55)
--------- --------- --------- --------- --------- ---------
December 31.................... 22,378,651 5,595 22,432,077 5,608 22,528,747 5,632
========= ========= ========= ========= ========= =========
Paid in surplus
January 1...................... 4,014 3,770 3,684
Premium on shares issued:
Employee share schemes....... 129 118 250
ARCO......................... 54 51 --
Repurchase of ordinary
share capital................ 25 39 55
Stamp duty reserve tax......... -- -- (295)
Qualifying Employee Share
Ownership Trust (d).......... 21 36 76
--------- --------- ---------
December 31.................... 4,243 4,014 3,770
========= ========= =========
The Notes to Financial Statements are an integral part of this Statement.
F - 6
BP p.l.c. AND SUBSIDIARIES
STATEMENT OF CHANGES IN BP SHAREHOLDERS' INTEREST (Continued)
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Merger reserve
January 1...................................................... 26,983 26,869 697
ARCO (b)....................................................... 50 114 --
ARCO acquisition............................................... -- -- 26,172
-------- -------- ---------
December 31.................................................... 27,033 26,983 26,869
======== ======== =========
Other reserves
January 1...................................................... 223 456 --
ARCO(b)........................................................ (50) (117) --
ARCO acquisition............................................... -- -- 456
Redemption of ARCO preference shares (e)....................... -- (116) --
-------- -------- ---------
December 31.................................................... 173 223 456
======== ======== =========
Retained earnings
January 1...................................................... 28,312 28,836 34,008
Prior year adjustment -- change in accounting policy........... -- -- (6,250)
-------- -------- ---------
As restated.................................................... 28,312 28,836 27,758
Currency translation differences (net of tax).................. 3,333 (828) (2,340)
Repurchase of ordinary share capital........................... (750) (1,281) (2,001)
Qualifying Employee Share Ownership Trust (d).................. (21) (36) (76)
Profit for the year............................................ 6,845 6,556 10,120
Dividends (f)
Preference (non-equity)...................................... (2) (2) (2)
Ordinary (equity)............................................ (5,373) (4,933) (4,623)
-------- -------- ---------
December 31.................................................... 32,344 28,312 28,836
======== ======== =========
----------
(a) Employee share schemes. During the year 33,820,750 ordinary shares were
issued under the BP, Amoco and Burmah Castrol employee share schemes.
(b) ARCO. 12,894,348 ordinary shares were issued in respect of ARCO employee
share option schemes.
(c) Repurchase of ordinary share capital. The Company purchased for
cancellation 100,140,987 ordinary shares for a total consideration of
$750 million.
(d) See Note 35 -- Employee share plans.
(e) Redemption of ARCO preference shares. A cash tender offer was made in March
2001 for the outstanding ARCO preference shares.
(f) See Note 15 -- Dividends per ordinary share.
(g) See Note 33 -- Retained earnings.
(h) Voting on substantive resolutions tabled at a general meeting is on a poll.
On a poll, shareholders present in person or by proxy have two votes for
every (pound)5 in nominal amount of the first and second preference shares
held and one vote for every ordinary share held. On a show of hands vote on
other resolutions (procedural matters) at a general meeting, shareholders
present in person or by proxy have one vote each.
The Notes to Financial Statements are an integral part of this Statement.
F - 7
BP p.l.c. AND SUBSIDIARIES
STATEMENT OF CHANGES IN BP SHAREHOLDERS' INTEREST (Concluded)
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.
The Notes to Financial Statements are an integral part of this Statement.
F - 8
BP 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. In preparing the financial statements for the current year, the Group
has adopted Financial Reporting Standard No. 19 'Deferred Tax' (FRS 19) and the
transitional disclosure requirements of Financial Reporting Standard No. 17
'Retirement Benefits' (FRS 17). The adoption of FRS 19 has resulted in a change
in accounting policy for deferred tax. See Note 45 New accounting standard for
deferred tax, for further information.
In addition to the requirements of accounting standards, the accounting for
exploration and production activities is governed by the Statement of
Recommended Practice ('SORP') 'Accounting for Oil and Gas Exploration,
Development, Production and Decommissioning Activities' issued by the UK Oil
Industry Accounting Committee on June 7, 2001.
These accounts have been prepared in accordance with the SORP's provisions
except for where royalties are payable in cash and the royalty holder does not
have a direct interest in the underlying reserves and production. In these
circumstances, the SORP recommends that turnover, reserves and production should
be presented on a gross basis with the royalty payable treated as an expense.
The Group has historically presented turnover, reserves and production net of
all royalties whether payable in cash or in kind. BP considers that such
presentation more appropriately reflects the nature of the profit sharing
arrangements.
Basis of preparation
The Group's main activities are the exploration and production of crude oil
and natural gas; the marketing and trading of natural gas and power; the
refining, marketing, supply and transportation of petroleum products; and the
manufacturing and marketing of petrochemicals.
The preparation of accounts in conformity with UK generally accepted
accounting practice requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the
accounts and the reported amounts of revenues and expenses during the reporting
period. Actual outcomes could differ from these estimates.
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, inventory 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, inventory holding gains or losses, interest expense,
taxation, gross assets and gross liabilities of the joint venture (the gross
equity method).
Certain of the Group's activities are conducted through joint arrangements
and are included in the consolidated financial statements in proportion to the
Group's interest in the income, expenses, assets and liabilities of these joint
arrangements.
On the acquisition of a subsidiary, or of an interest in a joint venture or
associate, fair values reflecting conditions at the date of acquisition are
attributed to the identifiable net assets acquired. When the cost of acquisition
exceeds the fair values attributable to the Group's share of such net assets the
difference is treated as purchased goodwill. This is capitalized and amortized
over its estimated useful economic life, which is usually 10 years.
Where an interest in a separate business of an acquired entity is held
temporarily pending disposal, it is carried on the balance sheet at its
estimated net proceeds of sale.
F - 9
BP 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, except as
explained under inventory valuation. Accounts prepared on this basis 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 inventory 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
inventory holding gains or losses and reflect the average cost of supplies
incurred during the year, and thus provide insight into underlying trading
results. Inventory holding gains or losses represent the difference between the
replacement cost of sales and the historical cost of sales calculated using the
first-in first-out method.
Inventory valuation
Inventories are valued at cost to the Group using the first-in first-out
method or at net realizable value, whichever is the lower. Stores are stated at
or below cost calculated mainly using the average method.
Inventory held for trading purposes is marked-to-market and any gains or
losses are recognized in the income statement rather than the statement of total
recognized gains and losses. The directors consider that the nature of the
Group's trading activity is such that, in order for the accounts to show a true
and fair view of the state of affairs of the Group and the results for the year,
it is necessary to depart from the requirements of Schedule 4 to the Companies
Act 1985. Had the treatment in Schedule 4 been followed, the profit and loss
account reserve would have been reduced by $209 million (2001 $84 million) and a
revaluation reserve established and increased accordingly.
Revenue recognition
Revenues associated with the sale of oil, natural gas liquids, LNG,
petroleum and chemical products and all other items are recognized when the
title passes to the customer. Generally, revenues from the production of natural
gas and oil properties in which the Group has an interest with other producers
are recognized on the basis of the Group's working interest in those properties
(the entitlement method). Differences between the production sold and the
Group's share of production are not significant.
Foreign currencies
On consolidation, assets and liabilities of subsidiaries are translated
into US dollars at closing rates of exchange. Income and cash flow statements
are translated at average rates of exchange. Exchange differences resulting from
the retranslation of net investments in subsidiaries, joint ventures and
associates at closing rates, together with differences between income statements
translated at average rates and at closing rates, are dealt with in reserves.
Exchange gains and losses arising on long-term foreign currency borrowings used
to finance the Group's foreign currency investments are also dealt with in
reserves. All other exchange gains or losses on settlement or translation at
closing rates of exchange of monetary assets and liabilities are included in the
determination of profit for the year.
F - 10
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (continued)
Derivative financial instruments
The Group uses derivative financial instruments (derivatives) to manage
certain exposures to fluctuations in foreign currency exchange rates and
interest rates, and to manage some of its margin exposure from changes in oil
and natural gas prices. Derivatives are also traded in conjunction with these
risk management activities.
The purpose for which a derivative contract is used is identified at
inception. To qualify as a derivative for risk management, the contract must be
in accordance with established guidelines which ensure that it is effective in
achieving its objective. All contracts not identified at inception as being for
the purpose of risk management are designated as being held for trading purposes
and accounted for using the fair value method, as are all oil price derivatives.
The Group accounts for derivatives using the following methods:
Fair value method: Derivatives are carried on the balance sheet at fair
value ('marked-to-market') with changes in that value recognized in earnings of
the period. This method is used for all derivatives which are held for trading
purposes. Interest rate contracts traded by the Group include futures, swaps,
options and swaptions. Foreign exchange contracts traded include forwards and
options. Oil and natural gas price contracts traded include swaps, options and
futures.
Accrual method: Amounts payable or receivable in respect of derivatives are
recognized ratably in earnings over the period of the contracts. This method is
used for derivatives held to manage interest rate risk. These are principally
swap agreements used to manage the balance between fixed and floating interest
rates on long-term finance debt. Other derivatives held for this purpose may
include swaptions and futures contracts. Amounts payable or receivable in
respect of these derivatives are recognized as adjustments to interest expense
over the period of the contracts. Changes in the derivative's fair value are not
recognized.
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 that 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.
F - 11
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (continued)
Tangible assets
The initial cost of a tangible fixed asset comprises its purchase or
construction cost and any cost directly attributable to bringing it into working
condition for its intended use. Capitalization of directly attributed costs
ceases when the physical construction of the tangible asset is complete. Any
subsequent expenditure that enhances an asset's operating performance or
replaces a fully depreciated component of an asset is capitalized.
Depreciation
Oil and gas production assets are depreciated using a unit-of-production
method based upon estimated proved reserves. Other tangible and intangible
assets are depreciated on the straight line method over their estimated useful
lives. The average estimated useful lives of refineries are 20 years, chemicals
manufacturing plants 20 years and service stations 15 years. Other intangibles
are amortized over a maximum period of 20 years.
The Group undertakes a review for impairment of a fixed asset or goodwill
if events or changes in circumstances indicate that the carrying amount of the
fixed asset or goodwill may not be recoverable. To the extent that the carrying
amount exceeds the recoverable amount, that is, the higher of net realizable
value and value in use, the fixed asset or goodwill is written down to its
recoverable amount. The value in use is determined from estimated discounted
future net cash flows.
Maintenance expenditure
Expenditure on major maintenance, refits or repairs is capitalized where it
enhances the performance of an asset above its originally assessed standard of
performance; replaces an asset or part of an asset which was separately
depreciated and which is then written off; or restores the economic benefits of
an asset which has been fully depreciated. All other maintenance expenditure is
charged to income as incurred.
Exploration expenditure
Exploration expenditure is accounted for in accordance with the successful
efforts method. Exploration and appraisal drilling expenditure is initially
capitalized as an intangible fixed asset. When proved reserves of oil and
natural gas are determined and development is sanctioned, the relevant
expenditure is transferred to tangible production assets. All exploration
expenditure determined as unsuccessful is charged against income. Exploration
licence acquisition costs are amortized over the estimated period of
exploration. Geological and geophysical exploration costs are charged against
income as incurred.
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.
F - 12
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (continued)
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 within finance debt. Rentals under operating leases are charged against
income as incurred.
Research
Expenditure on research is written off in the year in which it is incurred.
Interest
Interest is capitalized gross during the period of construction where it
relates either to the financing of major projects with long periods of
development or to dedicated financing of other projects. All other interest is
charged against income.
Pensions and other postretirement benefits
The cost of providing pensions and other postretirement benefits is charged
to income on a systematic basis, with pension surpluses and deficits amortized
over the average expected remaining service lives of current employees. The
difference between the amounts charged to income and the contributions made to
pension plans is included within other provisions or debtors as appropriate. The
amounts accrued for other postretirement benefits and unfunded pension
liabilities are included within other provisions.
F - 13
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (concluded)
Deferred taxation
Deferred tax is recognized in respect of all timing differences that have
originated but not reversed at the balance sheet date where transactions or
events have occurred at that date that will result in an obligation to pay more,
or a right to pay less, tax in the future. In particular:
-- Provision is made for tax on gains arising from the disposal of fixed
assets that have been rolled over into replacement assets, only to the
extent that, at the balance sheet date, there is a binding agreement
to dispose of the replacement assets concerned. However, no provision
is made where, on the basis of all available evidence at the balance
sheet date, it is more likely than not that the taxable gain will be
rolled over into replacement assets and charged to tax only where the
replacement assets are sold.
-- Provision is made for deferred tax that would arise on remittance of
the retained earnings of overseas subsidiaries, joint ventures and
associated undertakings only to the extent that, at the balance sheet
date, dividends have been accrued as receivable.
Deferred tax assets are recognized only to the extent that it is considered
more likely than not that there will be suitable taxable profits from which the
underlying timing differences can be deducted.
Deferred tax is measured on an undiscounted basis at the tax rates that are
expected to apply in the periods in which timing differences reverse, based on
tax rates and laws enacted or substantively enacted at the balance sheet date.
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
Information for 2001 and 2000 has been restated to reflect the transfer of
the solar, renewables and alternative fuels activities from Other businesses and
corporate to Gas, Power and Renewables. In addition, certain prior year figures
have been restated to conform with the 2002 presentation.
Note 2 -- Turnover
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Sales and operating revenue.................................... 222,231 208,299 168,709
Customs duties and sales taxes................................. 43,510 34,081 20,647
-------- -------- ---------
178,721 174,218 148,062
======== ======== =========
F - 14
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 3 -- Production taxes
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
UK petroleum revenue tax....................................... 309 600 707
Overseas production taxes...................................... 965 1,089 1,354
-------- -------- ---------
1,274 1,689 2,061
======== ======== =========
Note 4 -- Distribution and administration expenses
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Distribution................................................ 11,431 9,852 7,514
Administration.............................................. 1,201 1,066 1,817
-------- -------- ---------
12,632 10,918 9,331
======== ======== =========
Distribution and administration expenses for 2002 include Veba from
February 1. The expenses for 2002 and 2001 include Atlantic Richfield Company
(ARCO), Burmah Castrol and the European fuels business for the full year,
whereas for 2000 their costs were only included for part of the year, from April
14, July 7, and August 1, respectively.
Note 5 -- Other income
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Income from other fixed asset investments....................... 139 208 202
Other interest and miscellaneous income......................... 502 486 603
-------- -------- ---------
641 694 805
======== ======== =========
Income from investments publicly traded included above.......... 58 32 8
-------- -------- ---------
F - 15
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 6 -- Auditors' remuneration
Years ended December 31,
------------------------------------------------------
2002 2001 2000
---------------- ---------------- ---------------
UK Total UK Total UK Total
------ ------ ------ ------ ------ ------
($ million)
Audit fees -- Ernst & Young
Group audit........................................ 6 14 5 13 6 15
Local statutory audit and quarterly review......... 4 14 3 11 3 13
------ ------ ------ ------ ------ ------
10 28 8 24 9 28
====== ====== ====== ====== ====== ======
Fees for other services -- Ernst & Young
Audit-related services............................. 14 21 20 30 12 19
Taxation services.................................. 4 28 9 28 3 14
Other services..................................... 2 2 -- 1 5 18
------ ------ ------ ------ ------ ------
20 51 29 59 20 51
====== ====== ====== ====== ====== ======
The audit fees payable to Ernst & Young are reviewed by the Audit Committee
in the context of other global companies for cost effectiveness. The committee
also reviews the nature and extent of non-audit services to ensure that
independence is maintained.
Ernst & Young is selected to provide audit-related services in addition to
its statutory audit duties where its expertise and experience of BP are
important. The tax services were awarded either through a full competitive
tender process or following an assessment of the expertise of Ernst & Young
relative to that of other potential service providers. These services are for a
fixed term. The other services were awarded on a similar basis.
F - 16
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 7 -- Exceptional items
Exceptional items comprise profit (loss) on sale of fixed assets and the
sale of businesses or termination of operations, as follows:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Profit on sale of businesses or
termination of operations -- Group............................ 195 182 341
Loss on sale of businesses or
termination of operations -- Group............................ (228) (250) (209)
-------- -------- ---------
(33) (68) 132
-------- -------- ---------
Profit on sale of fixed assets -- Group............................ 2,736 948 535
-- Associated undertakings.......... 2 -- --
-- Joint ventures................... -- -- 24
Loss on sale of fixed assets -- Group............................ (1,537) (343) (471)
-- Associated undertakings.......... -- (2) --
-------- -------- ---------
1,201 603 88
-------- -------- ---------
Exceptional items...................................................... 1,168 535 220
Taxation credit (charge):
Sale of businesses or termination of operations...................... 45 (100) (86)
Sale of fixed assets................................................. (170) (270) (56)
-------- -------- ---------
Exceptional items (net of tax)....................................... 1,043 165 78
======== ======== =========
Sales of businesses or termination of operations
The profit on the sale of businesses in 2002 relates mainly to the disposal
of the Group's retail network in Cyprus and the UK contract energy management
business. For 2001 the profit relates to the sale of the Group's interest in
Vysis. For 2000 the profit is attributable primarily to the divestment by the
Group of its common interest in Altura Energy.
The loss on sale of businesses or termination of operations for 2002
represents the loss on disposal of the plastic fabrications business, the loss
on disposal of the former Burmah Castrol speciality chemicals business Fosroc
Construction, the loss on withdrawal from solar thin film manufacturing and the
provision for the loss on divestment of the former Burmah Castrol speciality
chemicals businesses Sericol and Fosroc Mining. The loss during 2001 arose
principally from the sale of the Group's Carbon Fibers business and the
write-off of assets following the closure or exit from certain chemicals
activities. The loss during 2000 arose from the subvention of bank loans to its
paraxylene joint venture in Singapore.
F - 17
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 7 -- Exceptional items (concluded)
Sale of fixed assets
The major part of the profit on the sale of fixed assets during 2002 arises
from the divestment of the Group's shareholding in Ruhrgas. The other
significant elements of the profit for the year are the gain on the redemption
of certain preferred limited partnership interests BP retained following the
Altura Energy common interest disposal in 2000 in exchange for BP loan notes
held by the partnership, the profit on the sale of the Group's interest in the
Colonial pipeline in the USA and the profit on the sale of a US downstream
electronic payment system. For 2001, the profit on the sale of fixed assets
includes the profit from the divestment of the refineries at Mandan, North
Dakota, and Salt Lake City, Utah; the Group's interest in the Alliance and
certain other pipeline systems in the USA; and BP's interest in the Kashagan
discovery in Kazakhstan. For 2000 the profit on sale of fixed assets included
the disposal of the Alliance refinery, located in Belle Chasse, Louisiana, the
profit from the divestment of a 10% interest in certain exploration and
production interests in Trinidad and the profit from the sale of other
exploration and production interests, mainly in the UK and USA.
The major element of the loss on sale of fixed assets in 2002 relates to
provisions for losses on sale of exploration and production properties in the
USA announced in early 2003. For 2001, the loss on sale of fixed assets arose
from a number of transactions. For 2000 the loss relates principally to the
divestment by the Group of its interests in the Quiriquire and Guarapiche fields
in Venezuela.
Additional information on the sale of businesses and fixed assets is given
in Note 19 -- Disposals.
Note 8 -- Interest expense
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Bank loans and overdrafts.................................. 134 119 154
Other loans (a)............................................ 852 1,111 1,221
Capital leases............................................. 40 78 107
-------- -------- ---------
1,026 1,308 1,482
Capitalized at 4% (2001 5% and 2000 7%).................... 100 81 119
-------- -------- ---------
Group...................................................... 926 1,227 1,363
Joint ventures............................................. 58 70 78
Associated undertakings.................................... 83 135 140
Unwinding of discount on provisions ....................... 170 196 189
Change in discount rate for provisions .................... 42 42 --
-------- -------- ---------
Total charged against profit............................... 1,279 1,670 1,770
======== ======== =========
----------
(a) Interest expense includes a charge of $15 million (2001 $62 million and
2000 $111 million) relating to early redemption of debt.
F - 18
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 9 -- Depreciation and amounts provided
Included in the income statement under the following headings:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Depreciation and amortization of goodwill and other intangibles
Replacement cost of sales.......................................... 9,346 7,475 6,480
Distribution....................................................... 952 1,221 707
Administration..................................................... 90 94 87
-------- -------- ---------
10,388 8,790 7,274
Amounts provided against fixed asset investments
Replacement cost of sales.......................................... 13 68 252
-------- -------- ---------
10,401 8,858 7,526
======== ======== =========
Depreciation of capitalized leased assets included above............. 49 65 79
======== ======== =========
The 2002 charge for depreciation and amortization of goodwill and other
intangibles includes asset write-downs and impairment charges of $1,390 million
in total. Exploration and Production recognized a charge of $1,091 million for
the impairment of Shearwater in the North Sea, Rhourde El Baguel in Algeria,
LL652 and Boqueron in Venezuela, Pagerungan in Indonesia and Badami in Alaska,
following full technical reassessments and evaluations of future investment
opportunities. In addition, the business took a $94 million write-off in respect
of its Gas-to-Liquids plant in Alaska. Chemicals wrote down the value of its
Indonesian manufacturing assets by $140 million following a review of immediate
prospects and opportunities for future growth in a highly competitive regional
market. Gas, Power and Renewables incurred an impairment charge of $30 million
in respect of a cogeneration power plant in the UK. Refining and Marketing
recognized an impairment charge of $35 million for its retail business in
Venezuela.
The charge for depreciation and amortization of goodwill and other
intangibles in 2001 included $175 million for the impairment of the upstream
Venezuelan Lake Maracaibo operation.
For 2000 the charge included $61 million for the write-down of Chemicals
and Exploration and Production assets. In addition, for 2000 $181 million was
provided against the Group's chemicals investment in Indonesia as a result of
the weak business environment in the region.
In assessing the value in use of potentially impaired assets, a discount
rate of 9% has been used. This is the rate used by the Company for investment
appraisal.
F - 19
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 10 -- Rental expense under operating leases
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Minimum rentals:
Tanker charters................................................ 397 393 361
Plant and machinery............................................ 621 530 471
Land and buildings............................................. 342 355 343
-------- -------- ---------
1,360 1,278 1,175
Less: Rentals from sub-leases.................................... (166) (165) (185)
-------- -------- ---------
1,194 1,113 990
======== ======== =========
Note 11 -- Research and development
Expenditure on research and development amounted to $373 million (2001
$385 million and 2000 $434 million).
Note 12 -- Currency exchange gains and losses
Accounted net foreign currency exchange gain included in the determination
of profit for the year amounted to $66 million (2001 $12 million gain and 2000
$30 million gain).
F - 20
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 13 -- Taxation
Tax on profit on ordinary activities
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Current tax:
UK corporation tax............................................ 1,304 1,666 1,505
Overseas tax relief........................................... (301) (678) (310)
-------- -------- ---------
1,003 988 1,195
Overseas...................................................... 1,883 3,846 3,704
-------- -------- ---------
Group......................................................... 2,886 4,834 4,899
Joint ventures................................................ 75 94 57
Associated undertakings....................................... 187 203 128
-------- -------- ---------
3,148 5,131 5,084
-------- -------- ---------
Deferred tax:
UK ........................................................... 433 (48) 12
Overseas...................................................... 761 1,292 1,552
-------- -------- ---------
1,194 1,244 1,564
-------- -------- ---------
Tax on profit on ordinary activities............................ 4,342 6,375 6,648
======== ======== =========
Included in the charge for the year is a charge of $125 million (2001 $370
million charge and 2000 $142 million charge) relating to exceptional items.
Tax included in statement of total recognised gains and losses
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Current tax:
UK............................................................ 57 (12) --
Overseas...................................................... (54) (4) (57)
-------- -------- ---------
3 (16) (57)
-------- -------- ---------
Deferred tax:
UK............................................................ 138 (14) --
Overseas...................................................... 1 -- --
-------- -------- ---------
139 (14) --
-------- -------- ---------
Tax included in statement of total recognized gains and losses.. 142 (30) (57)
======== ======== =========
F - 21
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 13 -- Taxation (continued)
Factors affecting current tax charge
The following table provides a reconciliation of the UK statutory
corporation tax rate to the effective current tax rate of the Group on profit
before taxation.
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Analysis of profit before taxation:
UK............................................................... 2,822 2,333 3,426
Overseas......................................................... 8,442 10,659 13,431
-------- -------- ---------
11,264 12,992 16,857
======== ======== =========
Taxation........................................................... 4,342 6,375 6,648
======== ======== =========
Effective tax rate................................................. 39% 49% 39%
======== ======== =========
(% of profit before tax)
UK statutory corporation tax rate.................................. 30 30 30
Increase (decrease) resulting from:
UK supplementary and overseas taxes at higher rates.............. 9 9 8
Tax credits...................................................... (3) (3) (4)
No relief for inventory holding losses
(inventory holding gains not taxed)............................ (2) 3 (1)
Current year losses unrelieved (prior year losses utilized)...... 1 4 2
Acquisition amortization......................................... 7 6 3
Other............................................................ (3) -- 1
-------- -------- ---------
Effective tax rate................................................. 39 49 39
Current year timing differences.................................... (11) (10) (9)
-------- -------- ---------
Effective current tax rate......................................... 28 39 30
======== ======== =========
Current year timing differences arise mainly from the excess of tax
depreciation over book depreciation.
Factors that may affect future tax charges
The Group earns income in many different countries and, on average, pays
taxes at rates higher than the UK statutory rate. The overall impact of these
higher taxes, which include the supplementary charge of 10% on UK North Sea
profits, is subject to changes in enacted tax rates and the country mix of the
Group's income. However, it is not expected to increase or decrease
substantially in the near term.
The major component of timing differences in the current year is
accelerated tax depreciation. Based on current capital investment plans, the
Group expects to continue to be able to claim tax allowances in excess of
depreciation in future years at a level similar to the current year.
F - 22
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 13 -- Taxation (continued)
The tax charge in 2002 reflected a benefit from 'non-conventional fuel
credits' in the USA. Those credits are no longer available after December 31,
2002. The effect of the loss of these credits on the overall tax charge is
likely to be offset by benefits from restructuring and planning initiatives.
The Group's profit before taxation includes inventory holding gains or
losses. These gains (or losses) are not taxed (or deductible) in certain
jurisdictions in which the Group operates, and therefore give rise to decreases
or increases in the effective tax rate. However, over the longer term,
significant changes in the tax rate would arise only in the event of a
substantial and sustained change in oil prices.
The Group has around $5.3 billion of carry-forward tax losses in the UK,
which would be available to offset against future taxable income. To date, tax
assets have been recognized on $840 million of those losses (i.e. to the extent
that it is regarded as more likely than not that suitable taxable income will
arise). It is unlikely that the Group's effective tax rate will be significantly
affected in the near term by utilization of losses not previously recognized as
deferred tax assets. Carry-forward losses in other taxing jurisdictions have not
been recognized as deferred tax assets, and are unlikely to have a significant
effect on the Group's tax rate in future years.
The impact on the tax rate of acquisition amortization (non-deductible
depreciation and amortization relating to the fixed asset revaluation
adjustments and goodwill consequent upon the ARCO and Burmah Castrol
acquisitions) is unlikely to change in the near term.
F - 23
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 13 -- Taxation (concluded)
Deferred tax
At December 31,
-------------------
2002 2001
------- -------
($ million)
Analysis of provision:
Depreciation.................................................................. (14,990) (12,511)
Other taxable timing differences.............................................. (1,837) (1,995)
Petroleum revenue tax......................................................... 567 390
Decommissioning and other provisions.......................................... 2,192 1,993
Tax credit and loss carry forward............................................. 273 184
Other deductible timing differences........................................... 281 237
------- -------
Deferred tax provision.......................................................... (13,514) (11,702)
======= =======
of which -- UK.................................................................. 2,906 2,071
-- Overseas............................................................ 10,608 9,631
======= =======
Year ended
December 31,
2002
------------
($ million)
Analysis of movements during the year:
At January 1.......................................................................... 11,702
Exchange adjustments.................................................................. 477
Acquisitions.......................................................................... 6
Charge for the year on ordinary activities............................................ 1,194
Charge for the year in the statement of total recognized gains and losses............. 139
Deletions/transfers................................................................... (4)
------
At December 31.......................................................................... 13,514
======
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
The charge for deferred tax on ordinary activities:
Origination and reversal of timing differences.................... 839 1,244 1,564
Effect of the introduction of supplementary UK corporation
tax of 10% on opening liability................................. 355 -- --
-------- -------- ---------
1,194 1,244 1,564
======== ======== =========
The charge (credit) for deferred tax in statement of
total recognized gains and losses:
Origination and reversal of timing differences.................... 139 (14) --
======== ======== =========
F - 24
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 14 -- Quarterly results of operations (unaudited)
Profit (loss)
Historical cost per
Group profit before Profit ordinary
turnover interest and tax (loss) share
--------- ---------------- ------- ------------
($ million) (cents)
Year ended December 31, 2002
First quarter................................ 36,290 2,422 1,296 5.78
Second quarter............................... 43,655 4,151 2,058 9.18
Third quarter................................ 49,054 3,856 2,840 12.67
Fourth quarter............................... 49,722 2,114 651 2.92
--------- --------- --------- ---------
Total........................................ 178,721 12,543 6,845 30.55
========= ========= ========= =========
Year ended December 31, 2001
First quarter................................ 45,412 5,452 2,830 12.59
Second quarter............................... 48,409 5,156 2,741 12.21
Third quarter................................ 43,580 3,509 1,588 7.08
Fourth quarter............................... 36,817 545 (603) (2.67)
--------- --------- --------- ---------
Total........................................ 174,218 14,662 6,556 29.21
========= ========= ========= =========
Year ended December 31, 2000
First quarter................................ 27,711 4,336 2,719 14.00
Second quarter............................... 33,158 4,688 2,578 11.56
Third quarter................................ 42,631 5,350 3,005 13.34
Fourth quarter............................... 44,562 4,253 1,818 7.87
--------- --------- --------- ---------
Total........................................ 148,062 18,627 10,120 46.77
========= ========= ========= =========
Note 15 -- Dividends per ordinary share
Years ended December 31,
---------------------------------------------------------------------
2002 2001 2000 2002 2001 2000 2002 2001 2000
------ ------ ------ ------ ------ ------ ------ ------ ------
(pence per share) (cents per share) ($ million)
First quarterly.................. 4.051 3.665 3.220 5.75 5.25 5.00 1,290 1,178 1,133
Second quarterly................. 3.875 3.911 3.352 6.00 5.50 5.00 1,346 1,235 1,128
Third quarterly.................. 3.897 3.805 3.602 6.00 5.50 5.25 1,340 1,232 1,185
Fourth quarterly................. 3.815 4.055 3.617 6.25 5.75 5.25 1,397 1,288 1,177
------ ------ ------ ------ ------ ------ ------ ------ ------
15.638 15.436 13.791 24.00 22.00 20.50 5,373 4,933 4,623
------ ------ ------ ------ ------ ------ ------ ------ ------
F - 25
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 16 -- Profit per ordinary share
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
(cents per share)
Basic earnings per share...................................... 30.55 29.21 46.77
Diluted earnings per share.................................... 30.41 29.04 46.46
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 outstanding
during the year. The profit attributable to ordinary shareholders is $6,843
million (2001 $6,554 million and 2000 $10,118 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:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
(shares thousand)
Weighted average number of ordinary shares.................... 23,397,126 22,435,737 21,638,280
Ordinary shares issuable under employee share schemes......... 107,322 137,988 144,869
---------- ---------- -----------
22,504,448 22,573,725 21,783,149
========== ========== ===========
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.
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
(cents per share)
Profit for the year............................................. 30.55 29.21 46.77
Inventory holding (gains) losses................................ (4.93) 8.47 (3.36)
-------- -------- ---------
Replacement cost profit for the year............................ 25.62 37.68 43.41
Exceptional items (net of tax).................................. (4.65) (0.73) (0.37)
-------- -------- ---------
Replacement cost profit before exceptional items................ 20.97 36.95 43.04
======== ======== =========
F - 26
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 17 -- Operating lease commitments
Annual commitments under operating leases were as follows:
December 31,
-----------------------------------------------
2002 2001
---------------------- ----------------------
Land and Land and
buildings Other buildings Other
--------- --------- --------- ---------
($ million)
Expiring within: 1 year................................. 80 174 28 313
2 to 5 years........................... 166 438 115 306
Thereafter............................. 289 188 184 113
------- ------- ------- -------
535 800 327 732
======= ======= ======= =======
The minimum future lease payments (after deducting related rental income
from operating sub-leases of $705 million) were as follows:
December 31,
2002
------------
($million)
2003............................................................ 1,203
2004............................................................ 975
2005............................................................ 859
2006............................................................ 778
2007............................................................ 643
Thereafter...................................................... 2,652
------------
7,110
============
F - 27
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 18 -- Acquisitions
2002 2001 2000
--------------------------------------------------- ------- --------
Fair value adjustments
------------------------
Book value Accounting
on policy
acquisition alignment Revaluations Fair value Fair value Fair value
---------- --------- ------------ ---------- ---------- ----------
($ million)
Intangible assets.......................... -- -- -- -- 194 2,549
Tangible assets............................ 2,562 262 2,121 4,945 841 21,768
Fixed assets-- investments................. 258 (136) -- 122 18 4,085
Businesses held for resale................. 900 -- 469 1,369 -- 5,926
Current assets (excluding cash)............ 2,905 126 -- 3,031 428 6,759
Cash at bank and in hand................... 1,118 -- -- 1,118 -- 1,790
Finance debt............................... (1,002) -- -- (1,002) (55) (7,942)
Other creditors............................ (3,219) (175) -- (3,394) (214) (7,193)
Deferred taxation.......................... (101) 5 90 (6) (3) (323)
Other provisions........................... (836) 3 (274) (1,107) (171) (3,254)
Net investment in equity accounted entities
transferred to full consolidation........ (191) -- -- (191) (170) --
-------- -------- -------- -------- -------- --------
Net assets acquired........................ 2,394 85 2,406 4,885 868 24,165
-------- -------- --------
Minority interests......................... (2,201) -- (1,840)
Goodwill................................... 342 48 11,669
-------- -------- --------
Consideration.............................. 3,026 916 33,994
======== ======== ========
Acquisitions in 2002
During the year BP acquired the whole of Veba Oil (Veba) from E.ON in two
stages. Veba owns Aral, Germany's biggest fuels retailer. In February BP paid
$1,072 million to subscribe for new shares issued by Veba and acquired $1,520
million of outstanding loans from E.ON to Veba in return for a 51% interest in
and operational control of Veba. In addition, there were acquisition expenses of
$30 million. Subsequently, on June 30, BP paid E.ON a further $2,386 million to
acquire the remaining 49% of Veba. There were further acquisition expenses of
$30 million. The total consideration of $5,038 million is subject to final
closing adjustments. Other transactions in 2002 included buying our
co-venturers' 15% interest in the ARCO polypropylene joint venture and acquiring
the 51% BP did not own in certain Chinese LPG ventures. All these business
combinations have been accounted for using the acquisition method of accounting.
The assets and liabilities acquired as part of the 2002 acquisitions are shown
in the above table in aggregate. The identifiable assets and liabilities of Veba
were not revalued on the acquisition of the 49% minority interest in June, as
the difference between the fair values and the carrying amounts of the assets
and liabilities was not material. Additional goodwill of $203 million was
recognized on the acquisition of the minority interest in Veba.
Fair values: The methods and assumptions used in estimating the fair values
of assets and liabilities acquired are set out in the following paragraphs.
Tangible assets: The fair value of refineries has been estimated by using
earnings multiples derived from other similar transactions. The fair value of
other tangible assets has been estimated by determining the net present value of
future cash flows.
Net assets of businesses held for resale: The fair value of the net assets
reflects the sales proceeds, less attributable taxation.
F - 28
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 18 -- Acquisitions (continued)
Finance debt: The debt acquired was floating rate debt and had maturity
dates of less than one year, so fair value approximates book value.
Other provisions: Liabilities for pensions have been estimated by
independent actuaries.
The fair values of other assets and liabilities acquired approximate their
book value.
Accounting policy alignment: The accounting policy alignment adjustments
represent the adjustments necessary to restate the balance sheets of the
acquired entities to conform with BP's accounting policies under UK GAAP. The
principal adjustments are set out below.
Fixed assets -- Investments: Interests in certain refinery joint ventures
were equity accounted by Veba. Under UK GAAP these interests are accounted for
as joint arrangements that are not entities.
Current assets: The basis of inventory valuation has been changed from
last-in first-out to first-in first-out.
Pro forma effects as required by US GAAP are not presented as they would
not materially change reported consolidated results of operations.
Acquisitions in 2001
During the year the Group acquired the 50% of Erdoelchemie, a
petrochemicals business based in Germany, it did not already own. In addition a
number of minor acquisitions were made. All these business combinations have
been accounted for using the acquisition method of accounting. The assets and
liabilities acquired as part of the 2001 acquisitions are shown in the above
table in aggregate. The fair value of tangible fixed assets has been estimated
by determining the net present value of future cash flows. No significant
adjustments were made to the other acquired assets and liabilities.
Acquisitions in 2000
In the year the Company acquired Atlantic Richfield Company (ARCO) and
Burmah Castrol p.l.c. (Burmah Castrol) and the 18% minority interest in Vastar
Resources Inc. (Vastar), a subsidiary of ARCO. The Company also purchased most
of ExxonMobil's assets used by the fuels refining and marketing operation in
Europe and made a number of minor acquisitions.
ARCO was acquired in April 2000. The total consideration for the
acquisition was $27,506 million, including acquisition expenses of $79 million,
and was effected by the issue of approximately 3,335 million BP ordinary shares.
In 2001, a cash tender offer was made for the outstanding ARCO preference stock.
The cash paid on redemption, $116 million, approximated the amount attributable
to the ARCO preference stock in the original determination of the consideration.
F - 29
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 18 -- Acquisitions (concluded)
The fair values of the assets and liabilities of ARCO included in the
accounts for the year ended December 31, 2000 have been subject to further
investigation and review during 2001, as permitted by Financial Reporting
Standard No. 7 'Fair Values in Acquisition Accounting'. The revisions to the
previously reported fair values are set out below.
Fair value
as previously Final
reported Revisions fair value
----------- ------- -------
($ million)
Intangible assets............................................. 2,549 -- 2,549
Tangible assets............................................... 19,829 (911) 18,918
Fixed assets-- investments.................................... 3,005 -- 3,005
Net assets of businesses held for resale...................... 5,290 -- 5,290
Current assets (excluding cash)............................... 3,668 -- 3,668
Cash at bank and in hand...................................... 994 -- 994
Finance debt.................................................. (6,796) -- (6,796)
Other creditors............................................... (3,475) 814 (2,661)
Deferred taxation............................................. (323) -- (323)
Other provisions.............................................. (3,009) -- (3,009)
------- ------- -------
Net assets acquired........................................... 21,732 (97) 21,635
Minority interests............................................ (1,595) -- (1,595)
Goodwill...................................................... 7,369 97 7,466
------- ------- -------
Consideration................................................. 27,506 -- 27,506
======= ======= =======
Tangible assets: The fair value attributed to certain exploration and
production assets has been revised following further technical studies.
Other creditors: Liabilities for taxation have been revised following a
review of outstanding liabilities.
BP completed the purchase of the minority interest in Vastar on September
15, 2000 for a total consideration of $1,618 million. This was settled in cash
and included expenses of $9 million and $94 million for the buy-out of employee
share options.
On July 7, 2000, the Company declared its cash offer for Burmah Castrol
unconditional. The total consideration was $4,909 million. Apart from the issue
of $130 million of loan notes the balance of the consideration was settled in
cash and included expenses of $16 million. The Company also acquired a further
20% interest in Castrol India at a cost of $178 million. This was settled in
2001.
On dissolution of the pan-European refining and marketing joint venture, BP
acquired most of the ExxonMobil assets used by the fuels operation for $1,479
million.
The Group undertook a number of other acquisitions in 2000 for an aggregate
consideration of $100 million.
F - 30
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 19-- Disposals
As part of the strategy to upgrade the quality of its asset portfolio, the
Group has an active programme to dispose of non-strategic assets. In the normal
course of business in any particular year, the group may sell interests in
exploration and production properties, service stations and pipeline interests
as well as non-core businesses.
Divestments in 2002. During the year, BP made a number of asset or business
disposals.
The major asset transactions during the year included the sale of the
Group's shareholding in Ruhrgas, the sale of a US downstream electronic payment
system, the Group's interest in the Colonial pipeline in the USA, the refinery
at Yorktown, Virginia, and the redemption of certain preferred partnership
interests BP retained following the disposal in 2000 of the Altura Energy common
interest in exchange for BP loan notes held by the partnership. The Group
entered into sale and leaseback transactions for certain chemicals manufacturing
facilities in the UK, a solar manufacturing facility in Spain and an LNG tanker.
In addition BP sold two-thirds of its interest in the European ethylene
pipeline company, ARG, in accordance with EU Commission requirements in relation
to the Veba acquisition.
BP closed its polypropylene production facility at Cedar Bayou, Texas, a
high density polyethylene unit at Deer Park, Texas, and one of four
polypropylene units at Chocolate Bayou, Texas.
BP sold its plastic fabrications business, Fosroc Construction, its UK
contract energy management business and its downstream retail businesses in
Cyprus and Japan. The Group also announced its withdrawal from solar thin film
manufacturing.
Divestments in 2001. The major transactions in 2001 included the sale of
the Group's interest in the Kashagan discovery in Kazakhstan; the divestment of
the refineries at Mandan, North Dakota, and Salt Lake City, Utah; the sale of
interests in the Alliance and certain other pipeline systems in the USA; and the
disposal of the Group's majority interest in Vysis.
At December 31, 2000, the Foseco, Fosroc Construction, Fosroc Mining and
Sericol speciality chemicals businesses that were acquired as part of the Burmah
Castrol acquisition were categorized as businesses held for resale. Foseco was
sold in July 2001. Fosroc Construction was sold in late 2002 and the sales of
the remaining two businesses were announced in January 2003. These three
businesses were consolidated from July 1, 2001 until their disposal.
A number of chemicals activities were either sold or terminated during
2001. Included in the businesses sold was the Carbon Fibers business.
The Group reduced its investment in Lukoil, which was acquired as part of
the ARCO acquisition, from 7% to 4% through the sale of 23.5 million shares.
To fulfil undertakings given to the European Commission at the time of the
ARCO acquisition, BP sold certain UK Southern North Sea natural gas interests in
April 2001.
Divestments in 2000. As a condition of the acquisition of Atlantic
Richfield Company (ARCO) in 2000 BP was required to divest ARCO's Alaskan
businesses and certain pipeline interests in the Lower 48. These operations were
sold for aggregate proceeds of $6,803 million. No profit or loss arose on these
disposals.
Other major disposals during 2000 were the sale of the Group's common
interest in Altura Energy; the sale of the Alliance refinery; the divestment of
exploration and production interests in Trinidad, the UK, USA and Venezuela; and
the sale of the Southern Company Energy Marketing.
F - 31
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 19 -- Disposals (concluded)
Total proceeds received for disposals represent the following amounts shown
in the cash flow statement:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Proceeds from the sale of businesses............................... 1,974 538 8,333
Proceeds from the sale of fixed assets............................. 2,470 2,365 3,029
Proceeds from the sale of investment in Ruhrgas.................... 2,338 -- --
-------- -------- ---------
6,782 2,903 11,362
======== ======== =========
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
The disposals comprise the following: ($ million)
Intangible assets.................................................. 205 183 458
Tangible assets (a)................................................ 2,545 1,481 3,224
Fixed asset -- investments......................................... 1,769 898 673
Net assets of businesses held for resale........................... 1,369 307 5,290
Finance debt....................................................... (1,135) -- --
Current assets less current liabilities............................ 533 (145) 919
Other provisions................................................... (109) (112) 631
-------- -------- ---------
5,177 2,612 11,195
Profit (loss) on sale of businesses or termination of operations... (33) (68) 132
Profit (loss) on sale of fixed assets.............................. 1,199 605 64
-------- -------- ---------
Total consideration................................................ 6,343 3,149 11,391
Decrease (increase) in amounts receivable from disposals........... 439 (246) (29)
-------- -------- ---------
Net cash inflow.................................................... 6,782 2,903 11,362
======== ======== =========
---------------
(a) Includes provision for loss on disposal of $1,204 million.
F - 32
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 20 -- Intangible assets
Exploration Other
expenditure Goodwill intangibles Total
---------- ---------- ---------- ----------
($ million)
Cost
At January 1, 2002........................................ 6,114 11,991 805 18,910
Prior year adjustment - change in accounting policy....... -- 1,081 -- 1,081
-------- -------- -------- --------
Restated.................................................. 6,114 13,072 805 19,991
Exchange adjustments...................................... 53 544 28 625
Acquisitions.............................................. -- 342 -- 342
Additions................................................. 886 203 92 1,181
Transfers................................................. (1,138) -- -- (1,138)
Deletions................................................. (285) (124) (118) (527)
-------- -------- -------- --------
At December 31, 2002...................................... 5,630 14,037 807 20,474
======== ======== ======== ========
Depreciation
At January 1, 2002........................................ 780 2,020 517 3,317
Prior year adjustment - change in accounting policy....... -- 185 -- 185
-------- -------- -------- --------
Restated.................................................. 780 2,205 517 3,502
Exchange adjustments...................................... 11 105 21 137
Charge for the year....................................... 385 1,302 169 1,856
Transfers................................................. (265) -- -- (265)
Deletions................................................. (225) (13) (84) (322)
-------- -------- -------- --------
At December 31, 2002...................................... 686 3,599 623 4,908
======== ======== ======== ========
Net book amount
At December 31, 2002...................................... 4,944 10,438 184 15,566
At December 31, 2001...................................... 5,334 10,867 288 16,489
======== ======== ======== ========
F - 33
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 21 -- Tangible assets
Property, plant and equipment:
Gas Other of which:
Exploration Power Refining businesses Assets
and and and and under
Production Renewables Marketing Chemicals corporate Total construction
---------- ---------- ---------- ---------- ---------- ---------- ------------
($ million)
Cost
At January 1, 2002............. 98,012 2,293 29,756 15,790 2,204 148,055 8,326
Exchange adjustments........... 4,014 64 2,249 1,021 82 7,430 287
Acquisitions................... 59 -- 4,331 555 -- 4,945 51
Additions...................... 8,204 287 2,598 668 209 11,966 8,849
Transfers...................... 1,636 -- (339) (81) -- 1,216 (4,819)
Deletions...................... (1,213) (300) (1,747) (899) (291) (4,450) (567)
------- ------- ------- ------- ------- ------- -------
At December 31, 2002........... 110,712 2,344 36,848 17,054 2,204 169,162 12,127
======= ======= ======= ======= ======= ======= =======
Depreciation
At January 1, 2002............. 49,742 649 12,853 6,548 853 70,645
Exchange adjustments........... 2,326 8 837 360 21 3,552
Charge for the year............ 6,110 111 1,914 709 73 8,917
Provision for loss on disposal. 1,187 -- -- 17 -- 1,204
Transfers...................... 265 -- 6 -- -- 271
Deletions...................... (1,122) (24) (1,195) (660) (108) (3,109)
------- ------- ------- ------- ------- -------
At December 31, 2002........... 58,508 744 14,415 6,974 839 81,480
======= ======= ======= ======= ======= =======
Net book amount
At December 31, 2002........... 52,204 1,600 22,433 10,080 1,365 87,682 12,127
At December 31, 2001........... 48,270 1,644 16,903 9,242 1,351 77,410 8,326
======= ======= ======= ======= ======= ======= =======
Assets held under capital leases, capitalized interest and land at net book
amount included above:
Leased assets Capitalized interest
----------------------------------- -----------------------------------
Cost Depreciation Net Cost Depreciation Net
-------- ----------- -------- -------- ----------- --------
($ million) ($ million)
At December 31, 2002................ 1,694 904 790 3,329 1,617 1,712
At December 31, 2001................ 1,517 837 680 3,018 1,480 1,538
======= ======= ======= ======= ======= =======
Leasehold land
--------------------------
Over 50 years
Freehold land unexpired Other
------------- ------------- ----------
($ million)
At December 31, 2002........................................ 2,919 48 171
At December 31, 2001........................................ 2,279 211 170
======= ======= =======
F - 34
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 22 -- Fixed assets -- investments
Joint ventures Associated undertakings
--------------------- -----------------------
Net assets Net assets Other Own Listed
(liabilities) Loans (liabilities) Loans Loans shares(a) investments(b) Other(c) Total
----------- ------ ----------- ----- ----- ------ ----------- ------ ------
($ million)
Cost
At January 1, 2002......... 2,722 1,139 4,806 1,280 181 266 1,287 998 12,679
Prior year adjustment -
change in accounting
policy................... -- -- (84) -- -- -- -- -- (84)
------ ------ ------ ------ ------ ------ ------ ------ ------
Restated................... 2,722 1,139 4,722 1,280 181 266 1,287 998 12,595
Exchange adjustments....... (16) 17 89 48 16 19 142 9 324
Additions and net
movements in
joint ventures........... 182 178 898 62 43 18 3 3 1,387
Acquisitions............... -- -- 2 1 23 -- 72 24 122
Transfers.................. (112) (79) (243) (77) (14) -- 105 (746) (1,166)
Deletions.................. -- -- (1,453) (53) (92) (144) -- (31) (1,773)
------ ------ ------ ------ ------ ------ ------ ------ ------
At December 31, 2002....... 2,776 1,255 4,015 1,261 157 159 1,609 257 11,489
====== ====== ====== ====== ====== ====== ====== ====== ======
Amounts provided
At January 1, 2002......... -- -- 218 351 19 -- -- 44 632
Exchange adjustments....... -- -- 5 31 -- -- -- 1 37
Provided in the year....... -- -- -- 49 -- -- -- (36) 13
Transfers.................. -- -- -- -- -- -- -- -- --
Deletions.................. -- -- (4) -- -- -- -- -- (4)
------ ------ ------ ------ ------ ------ ------ ------ ------
At December 31, 2002....... -- -- 219 431 19 -- -- 9 678
====== ====== ====== ====== ====== ====== ====== ====== ======
Net book amount
At December 31, 2002....... 2,776 1,255 3,796 830 138 159 1,609 248 10,811
At December 31, 2001....... 2,722 1,139 4,504 929 162 266 1,287 954 11,963
====== ====== ====== ====== ====== ====== ====== ====== ======
----------
(a) Own shares are held in Employee Share Ownership Plans (ESOPs) to meet the
future requirements of the employee share plans (see Note 35) and prior to
award under the Long Term Performance Plan (see Note 36). At December 31,
2002 the ESOPs held 18,673,675 shares (34,005,910 shares at December 31,
2001) for the employee share schemes and 3,901,317 shares (7,673,056 shares
at December 31, 2001) for the Long Term Performance Plan. The market value
of these shares at December 31, 2002 was $154 million ($323 million at
December 31, 2001).
(b) The market value of listed investments at December 31, 2002 was $1,661
million ($1,284 million at December 31, 2001).
(c) Other investments are not publicly traded.
F - 35
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 23 -- Inventories
At December 31,
-------------------
2002 2001
------- -------
($ million)
Petroleum....................................................... 7,647 5,176
Chemicals....................................................... 966 953
Other........................................................... 675 568
------ ------
9,288 6,697
Stores.......................................................... 893 934
------ ------
10,181 7,631
====== ======
Replacement cost................................................ 10,610 7,686
====== ======
Note 24 -- Receivables
December 31, 2002 December 31, 2001
------------------ -----------------
Within After Within After
1 year 1 year(a) 1 year 1 year(a)
------ ------ ------ ------
($ million)
Trade receivables.......................... 18,798 -- 15,436 --
====== ====== ====== ======
Other receivables:
Joint ventures........................... 70 -- 32 --
Associated undertakings.................. 282 96 236 49
Prepayments and accrued income........... 2,716 1,771 2,143 789
Taxation recoverable..................... 94 9 335 8
Pension prepayment....................... -- 3,899 -- 3,417
Other.................................... 4,945 470 3,806 418
------ ------ ------ ------
8,107 6,245 6,552 4,681
====== ====== ====== ======
Provisions for doubtful debts deducted from Trade receivables amounted to
$445 million ($290 million at December 31, 2001).
----------
(a) See Note 50 -- US generally accepted accounting principles.
Note 25 -- Current assets -- investments
At December 31,
-------------------
2002 2001
------- -------
($ million)
Publicly traded -- UK........................................ 32 49
-- Foreign................................... 29 30
------ ------
61 79
Not publicly traded.......................................... 154 371
------ ------
215 450
====== ======
Stock exchange value of publicly traded investments.......... 61 88
====== ======
F - 36
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 26 -- Financial instruments
The Group co-ordinates 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 finance debt, cash, other
significant financial risks and relationships with banks and other financial
institutions. International oil and natural gas trading and risk management
relating to business operations are carried out by the Group's oil and natural
gas trading units.
The main financial risks faced by the Group through its normal business
activities are market risk, credit risk and liquidity risk. These risks and the
Group's approach to dealing with them are discussed below.
Market risk
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. Market
risks are managed using a range of derivatives. The Group also trades
derivatives in conjunction with these risk management activities.
All 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. A Trading Risk
Management Committee has oversight of the quality of internal control in the
Group's trading units. Independent control functions monitor compliance with
BP's policies. The control framework includes prescribed trading limits that are
reviewed regularly by senior management, daily monitoring of risk exposure using
value-at-risk principles, marking trading exposures to market and stress testing
to assess the exposure to potentially extreme market situations.
For market risk management and trading, conventional exchange-traded
derivative instruments such as futures and options are used as well as
non-exchange-traded instruments such as swaps, 'over-the-counter' 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, 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
earnings in the current period.
Currency exchange rates: Fluctuations in exchange rates can have
significant effects on the Group's reported profit. The effects of most exchange
rate fluctuations are absorbed in 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 profit.
F - 37
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 26 -- Financial instruments (continued)
The main underlying economic currency of the Group's cash flows is the US
dollar. This is because BP's major product, oil, is priced internationally in US
dollars. BP's foreign exchange management policy is to minimize economic and
significant transactional exposures arising 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 risks, and then dealing with any material residual
foreign exchange risks. Significant residual non-dollar exposures are managed
using a range of derivatives.
In addition, most Group borrowings are in US dollars or are hedged with
respect to the US dollar.
Interest rates: The 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 the
maturity of debt, the Group manages interest expense 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 Group uses derivatives to manage the balance between fixed and floating
rate debt. During 2002, the proportion of floating rate debt was in the range
41-60% of total net debt outstanding.
Oil and natural gas prices: BP's trading function 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. They also use financial and commodity
derivatives to manage certain of the Group's exposures to price fluctuations on
natural gas transactions.
Credit risk
Credit risk is the potential exposure of the Group to loss in the event of
non-performance by a counterparty. The credit risk arising from the Group's
normal commercial operations is controlled by individual operating units within
guidelines. In addition, as a result of its use of derivatives, to manage market
risk, the Group has credit exposures through its dealings in the financial and
specialized oil and natural gas markets. The Group controls the related credit
risk through credit approvals, limits, use of netting arrangements and
monitoring procedures. Counterparty credit validation, independent of the
dealers, is undertaken before contractual commitment.
Concentrations of credit risk
The primary activities of the Group are oil and natural gas exploration and
production, gas and power marketing and trading, oil refining and marketing and
the manufacture and marketing of chemicals. The Group's principal customers,
suppliers and financial institutions with which it conducts business are located
throughout the world. The credit ratings of interest rate and currency swap
counterparties are all of at least investment grade. The credit quality is
actively managed over the life of the swap.
F - 38
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 26 -- Financial instruments (continued)
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 also has undrawn
committed borrowing facilities to meet currently foreseeable borrowing
requirements.
At December 31, 2002 the Group had substantial amounts of undrawn borrowing
facilities available, including committed facilities of $3,600 million expiring
in 2003 ($3,400 million at December 31, 2001 expiring in 2002). These facilities
are with a number of international banks and borrowings under them would be at
pre-agreed rates. The Group expects to renew these facilities on an annual
basis. Certain of these facilities support the Group's commercial paper
programme.
Financial instruments
Financial instruments comprise primary financial instruments (cash, fixed
and current asset investments, debtors, creditors, finance debt and provisions)
and derivative financial instruments (interest rate contracts, foreign exchange
contracts, oil price contracts and natural gas price contracts). Interest rate
contracts include futures contracts, swap agreements and options. Foreign
exchange contracts include forwards, futures contracts, swap agreements and
options. Oil and natural gas price contracts are those that require settlement
in cash and include futures contracts, swap agreements and options. Oil and
natural gas price contracts that require physical delivery are not financial
instruments. However, if it is normal market practice for a particular type of
oil and natural gas contract, despite having contract terms that require
settlement by delivery, to be extinguished other than by physical delivery (e.g.
by cash payment) it is called a cash-settled commodity contract. Contracts of
this type are included with derivatives in the disclosures in Notes 27 and 28.
With the exception of the table of currency exposures shown on page F-41,
short-term debtors and creditors that arise directly from the group's operations
have been excluded from the disclosures contained in this note, as permitted by
Financial Reporting Standard No. 13 'Derivatives and Other Financial
Instruments: Disclosures'.
Maturity profile of financial liabilities
The profile of the maturity of the financial liabilities included in the
Group's balance sheet is shown in the table below.
December 31, 2002 December 31, 2001
------------------------------------- ------------------------------------
Other Other
Finance financial Finance financial
debt liabilities Total debt liabilities Total
---------- ----------- ---------- ---------- ----------- ----------
($ million)
Due within: 1 year........... 10,086 -- 10,086 9,090 -- 9,090
1 to 2 years..... 913 597 1,510 1,460 699 2,159
2 to 5 years..... 5,083 332 5,415 2,858 798 3,656
Thereafter....... 5,926 2,218 8,144 8,009 1,278 9,287
--------- --------- --------- --------- --------- ---------
22,008 3,147 25,155 21,417 2,775 24,192
========= ========= ========= ========= ========= =========
F - 39
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 26 -- Financial instruments (continued)
Interest rate and currency of financial liabilities
The interest rate and currency profile of the financial liabilities of the
Group, at December 31, after taking into account the effect of interest rate
swaps, currency swaps and forward contracts, is set out below.
Fixed rate Floating rate Interest free
-------------------------------------- ---------------------- ---------------------
Weighted Weighted
Weighted average time Weighted average time
average for which average until
interest rate rate is fixed Amount interest rate Amount maturity Amount Total
------------- ------------- ------ ------------- ------ ------------ ------ -----
(%) (Years)($ million) (%) ($ million) (Years)($ million)($ million)
At December 31, 2002
Finance debt
US dollar............ 7 7 7,818 2 13,287 -- -- 21,105
Sterling............. -- -- -- 4 103 -- -- 103
Other currencies..... 7 11 317 5 483 -- -- 800
------- ------- ------- -------
8,135 13,873 -- 22,008
------- ------- ------- -------
Other financial liabilities
US dollar............ 6 6 392 8 776 5 1,205 2,373
Sterling............. -- -- -- -- -- 6 171 171
Other currencies..... -- -- -- -- -- 2 603 603
------- ------- ------- -------
392 776 1,979 3,147
------- ------- ------- -------
Total 8,527 14,649 1,979 25,155
======= ======= ======= =======
At December 31, 2001
Finance debt
US dollar............ 7 8 11,603 2 9,365 -- -- 20,968
Sterling............. -- -- -- 4 133 -- -- 133
Other currencies..... 10 29 122 6 194 -- -- 316
------- ------- ------- -------
11,725 9,692 -- 21,417
------- ------- ------- -------
Other financial liabilities
US dollar............ 10 6 21 8 778 4 1,528 2,327
Sterling............. -- -- -- -- -- 3 114 114
Other currencies..... -- -- -- -- -- 2 334 334
------- ------- ------- -------
21 778 1,976 2,775
------- ------- ------- -------
Total 11,746 10,470 1,976 24,192
======= ======= ======= =======
December 31,
------------------
2002 2001
------- -------
($ million)
Analysis of the above financial liabilities by balance sheet caption:
Current liabilities-- falling due within one year
-- Finance debt................................................................. 10,086 9,090
Noncurrent liabilities
-- Finance debt................................................................. 11,922 12,327
-- Accounts payable and accrued liabilities..................................... 1,953 1,673
Provisions for liabilities and charges
-- Other provisions............................................................. 1,194 1,102
------- -------
25,155 24,192
======= =======
F - 40
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 26 -- Financial instruments (continued)
The other financial liabilities comprise various accruals, sundry creditors
and provisions relating to the Group's normal commercial operations, with
payment dates spread over a number of years.
The Group aims for a balance between floating and fixed interest rates and,
in 2002, the proportion of floating rate debt was in the range 41-60% 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 London Inter-Bank Offer Rate (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 finance debt and hedges described above, it is estimated that a change of
1% in the general level of interest rates on January 1, 2003 would change 2003
profit before tax by approximately $130 million.
Interest rate swaps and futures are used by the Group to modify the
interest characteristics of its long-term finance debt from a fixed to a
floating rate basis or vice versa. The following table indicates the types of
instruments used and their weighted average interest rates as at December 31.
December 31,
----------------------
2002 2001
----- -----
($ million except percentages)
Receive fixed rate swaps-- notional amount....................... 3,789 999
Average receive fixed rate ...................................... 5.0% 5.6%
Average pay floating rate........................................ 1.5% 2.3%
Pay fixed rate swaps-- notional amount........................... 2,169 2,914
Average pay fixed rate........................................... 6.6% 6.6%
Average receive floating rate.................................... 1.5% 2.3%
Futures contracts -- notional amount............................. -- 760
Average pay fixed rate........................................... -- 2.7%
Currency exchange rate risk
The monetary assets and monetary liabilities of the Group in currencies
other than in the functional currency of individual operating units are
summarized below. These currency exposures arise from normal trading activities.
As at December 31, 2002 and 2001, these exposures were as shown below.
Net foreign currency monetary assets (liabilities)
-------------------------------------------------------------
US dollar Sterling Euro Other Total
--------- -------- -------- -------- --------
($ million)
At December 31, 2002
US dollar........................................ -- 323 2 301 626
Sterling......................................... 412 -- 409 (33) 788
Other............................................ (717) (10) (194) (49) (970)
-------- -------- -------- -------- --------
(305) 313 217 219 444
======== ======== ======== ======== ========
At December 31, 2001
US dollar........................................ -- (193) 10 (15) (198)
Sterling......................................... 69 -- 237 182 488
Other............................................ (487) (241) (3) (27) (758)
-------- -------- -------- -------- --------
(418) (434) 244 140 (468)
======== ======== ======== ======== ========
F - 41
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 26 -- Financial instruments (concluded)
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 table in Note 28.
Interest rate and currency of financial assets
The following table shows the interest rate and currency profile of the
Group's material financial assets.
Fixed rate Floating rate Interest free
-------------------------------------- ---------------------- ---------------------
Weighted Weighted
Weighted average time Weighted average time
average for which average until
interest rate rate is fixed Amount interest rate Amount maturity Amount Total
------------- ------------- ------ ------------- ------ ------------ ------ -----
(%) (Years)($ million) (%) ($ million) (Years)($ million)($ million)
At December 31, 2002
US dollar............. 3 2 180 1 873 2 1,094 2,147
Sterling.............. 7 2 94 5 171 2 235 500
Other currencies...... 2 1 34 1 208 1 1,264 1,506
------- ------- ------- -------
308 1,252 2,593 4,153
======= ======= ======= =======
At December 31, 2001
US dollar............. 3 1 92 2 574 2 2,319 2,985
Sterling.............. 7 2 81 4 11 2 762 854
Other currencies...... 5 1 181 5 264 1 192 637
------- ------- ------- -------
354 849 3,273 4,476
======= ======= ======= =======
December 31,
-----------------
2002 2001
------- -------
($ million)
Analysis of the above financial assets by balance sheet caption:
Fixed assets -- investments..................................................... 1,995 2,403
Current assets
-- Receivables -- amounts falling due after more than one year.................. 423 265
-- Investments.................................................................. 215 450
-- Cash at bank and in hand..................................................... 1,520 1,358
------- -------
4,153 4,476
======= =======
The floating rate financial assets earn interest at various rates set
principally with respect to LIBOR or the local market equivalent.
Fixed asset investments included in the table above are held for the long
term and have no maturity period. They are excluded from the calculation of
weighted average time until maturity.
F - 42
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 27 -- Derivative financial instruments
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 sheet floating rate and
fixed rate debt. The Group also manages certain of its exposures to movements in
oil and natural gas prices. In addition, the Group trades derivatives in
conjunction with these risk management activities.
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.
Not recognized Carried forward in the
in the accounts balance sheet
------------------------- ------------------------
Gains Losses Total Gains Losses Total
------- ------- ------- ------- ------- -------
($ million)
Gains and losses at January 1, 2002.................. 109 (235) (126) 113 (327) (214)
of which accounted for in income in 2002........... 60 (19) 41 50 (162) (112)
Gains and losses at December 31, 2002................ 526 (450) 76 352 (28) 324
of which expected to be recognized in income
in 2003............................................ 96 (51) 45 200 (14) 186
Gains and losses at January 1, 2001.................. 303 (302) 1 56 (443) (387)
of which accounted for in income in 2001........... 203 (154) 49 22 (194) (172)
Gains and losses at December 31, 2001................ 109 (235) (126) 113 (327) (214)
of which expected to be recognized in income
in 2002............................................ 60 (19) 41 50 (162) (112)
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.
F - 43
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 27 -- Derivative financial instruments (continued)
The following table shows the fair value at December 31, of derivatives and
other financial instruments held for trading purposes. The fair values at the
year end are not materially unrepresentative of the position throughout the
year.
December 31,
-------------------------------------------------
2002 2001
----------------------- -----------------------
Fair value Fair value Fair value Fair value
asset liability asset liability
---------- ---------- ---------- ----------
($ million)
Interest rate contracts................................... -- -- -- --
Foreign exchange contracts................................ 29 (17) 14 (17)
Oil price contracts....................................... 440 (418) 248 (222)
Natural gas price contracts............................... 1,112 (955) 799 (787)
-------- -------- -------- --------
1,581 (1,390) 1,061 (1,026)
======== ======== ======== ========
The Group measures its market risk exposure, i.e. potential gain or loss in
fair values, on its trading activity using value-at-risk techniques. These
techniques are based on a variance/covariance model or a Monte Carlo simulation
and make a statistical assessment of the market risk arising from possible
future changes in market values over a 24-hour period. The calculation of the
range of potential changes in fair value takes into account a snapshot of the
end-of-day exposures, and the history of one-day price movements over the
previous 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 and natural gas price exposure also includes cash-settled
commodity contracts such as forward contracts.
The following table shows values at risk for trading activities.
Years ended December 31,
--------------------------------------------------------------------------
2002 2001
------------------------------------ -------------------------------------
High Low Average Year end High Low Average Year end
------- ------- ------- ------- ------- ------- ------- -------
($million)
Interest rate trading.......... -- -- -- -- 1 -- -- --
Foreign exchange trading....... 2 -- 1 -- 3 -- 1 --
Oil price trading.............. 34 14 23 19 29 10 18 17
Natural gas price trading...... 18 1 6 9 21 4 10 9
F - 44
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 27 -- Derivative financial instruments (concluded)
The presentation of trading results shown in the table below includes
certain activities of BP's trading function which involves the use of derivative
financial instruments in conjunction with physical and paper trading of oil and
natural gas. It is considered that a more comprehensive representation of the
Group's oil and natural gas price trading activities is given by aggregating the
gain or loss on such derivatives together with the gain or loss arising from the
physical and paper trades to which they relate, representing the net result of
the trading portfolio.
Years ended December 31,
----------------------
2002 2001
------ ------
Net gain Net gain
(loss) (loss)
------ ------
($ million)
Oil price trading....................................... 597 684
Natural gas price trading............................... 199 276
Interest rate trading................................... -- 1
Foreign exchange trading................................ 90 81
------ ------
886 1,042
====== ======
Note 28 -- 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. 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 include futures contracts, swap agreements and options and
cash-settled commodity contracts such as forward contracts.
Short-term debtors and creditors that arise directly from the Group's
operations have been excluded from the disclosures contained in this note, as
permitted by Financial Reporting Standard No.13 'Derivatives and Other Financial
Instruments: Disclosures'.
F - 45
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Fair values of financial assets and liabilities (continued)
The fair value and carrying amounts of finance debt shown below exclude the
effects of currency swaps, interest rate swaps and forward contracts (which are
included for presentation in the balance sheet). Long-term borrowings in the
table below include debt that matures in the year from December 31, 2002,
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.
December 31,
------------------------------------------------------------------------
2002 2001
----------------------------------- -----------------------------------
Net carrying Net carrying
Net fair value amount Net fair value amount
asset (liability) asset (liability) asset (liability) asset (liability)
---------------- ---------------- ---------------- ----------------
($ million)
Primary financial instruments
Fixed assets -- investments.......................... 2,047 1,995 2,400 2,403
Current assets
-- Other receivables-- amounts falling
due after more than one year.................... 423 423 265 265
-- Investments....................................... 215 215 459 450
-- Cash at bank and in hand.......................... 1,520 1,520 1,358 1,358
Finance debt
-- Short-term borrowings............................. (5,504) (5,504) (5,185) (5,185)
-- Long-term borrowings.............................. (15,476) (14,609) (14,875) (14,360)
-- Net obligations under finance leases.............. (2,183) (2,172) (1,619) (1,608)
Noncurrent liabilities
-- Accounts payable and accrued liabilities.......... (1,953) (1,953) (1,673) (1,673)
Provisions for liabilities and charges
-- Other provisions.................................. (1,194) (1,194) (1,102) (1,102)
Derivative financial or commodity instruments
Risk management -- interest rate contracts........... (63) -- (139) --
-- foreign exchange contracts........ 416 277 (251) (264)
-- oil price contracts............... 9 9 -- --
-- natural gas price contracts....... 5 5 (259) (259)
Trading -- interest rate contracts........... -- -- -- --
-- foreign exchange contracts........ 12 12 (3) (3)
-- oil price contracts............... 22 22 26 26
-- natural gas price contracts....... 157 157 12 12
F - 46
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Fair values of financial assets and liabilities (concluded)
The following methods and assumptions were used by the Group in estimating
its fair value disclosures for its financial instruments:
Fixed assets - Investments: The carrying amount reported in the balance
sheet for unlisted fixed asset investments approximates their fair value. The
fair value of listed fixed asset investments has been determined by reference to
market prices.
Current assets - Other receivables - amounts falling due after more than
one year: The fair value of other receivables 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.
Noncurrent liabilities - Accounts payable and accrued liabilities: 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 thus approximates the fair value.
Derivative financial instruments and cash-settled commodity contracts: The
fair values of the Group's interest rate and foreign exchange contracts are
based on pricing models which take into account relevant market data. 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.
F - 47
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 29 -- Finance debt
December 31, 2002 December 31, 2001
---------------------------- ---------------------------
Within After Within After
1 year(a) 1 year Total 1 year(a) 1 year Total
------ ------ ----- ------ ------ -----
($ million)
Bank loans.................................... 476 344 820 371 409 780
Other loans................................... 9,526 9,656 19,182 8,647 10,349 18,996
------ ------ ------ ------ ------ ------
Total borrowings.............................. 10,002 10,000 20,002 9,018 10,758 19,776
Net obligations under capital leases.......... 84 1,922 2,006 72 1,569 1,641
------ ------ ------ ------ ------ ------
10,086 11,922 22,008 9,090 12,327 21,417
====== ====== ====== ====== ====== ======
---------------
(a) Amounts due within one year include current maturities of long-term debt.
Where finance debt is swapped into another currency, the finance debt is
accounted in the swap currency and not in the original currency of denomination.
Total finance debt includes an asset of $277 million (a liability of $264
million at December 31, 2001) 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 $1,881 million (December 31, 2001 $1,768 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 has not experienced any
significant repurchases. BP considers these bonds to represent long-term funding
when assessing the maturity profile of its finance debt.
At December 31, 2002, the Group's share of third party finance debt of
joint ventures and associated undertakings was $457 million (December 31, 2001
$460 million) and $849 million (December 31, 2001 $1,136 million) respectively.
These amounts are not reflected in the Group's debt on the balance sheet.
F - 48
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 29 -- Finance debt (continued)
December 31, 2002 December 31, 2001
------------------------------------- ------------------------------------
Analysis of borrowings Bank Other Bank Other
by year of repayment loans loans Total loans loans Total
---------- --------- --------- ---------- --------- ---------
($ million)
Due after 10 years............ -- 1,417 1,417 42 3,188 3,230
Due within 10 years............ 1 371 372 150 312 462
9 years............. 43 310 353 -- 15 15
8 years............. -- 15 15 -- 1,411 1,411
7 years............. -- 1,699 1,699 -- 593 593
6 years............. -- 516 516 -- 879 879
5 years............. -- 1,603 1,603 -- 501 501
4 years............. 161 344 505 24 1,542 1,566
3 years............. 19 2,671 2,690 15 626 641
2 years............. 120 710 830 178 1,282 1,460
--------- --------- --------- --------- --------- ---------
344 9,656 10,000 409 10,349 10,758
1 year.............. 476 9,526 10,002 371 8,647 9,018
--------- --------- --------- --------- --------- ---------
820 19,182 20,002 780 18,996 19,776
========= ========= ========= ========= ========= =========
Amounts included above repayable by instalments part of which falls due
after five years from December 31, are as follows:
At December 31,
--------------------
2002 2001
------- -------
($ million)
After five years....................................................... 541 120
Within five years...................................................... 103 1,071
------ ------
644 1,191
====== ======
Interest rates on borrowings repayable wholly or partly more than five
years from December 31, 2002 range from 1% to 12% with a weighted average of 4%.
The weighted average interest rate on finance debt is 4%.
F - 49
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 29 -- 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:
December 31,
2002
-------------
($ million)
2003................................................................. 106
2004................................................................. 204
2005................................................................. 211
2006................................................................. 218
2007................................................................. 203
Thereafter........................................................... 3,481
-----------
4,423
Less: amount representing lease interest............................. (2,417)
-----------
Present value of net minimum capital lease payments.................. 2,006
===========
of which -- due within one year.................................... 84
-- due after one year..................................... 1,922
-----------
F - 50
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 29 -- Finance debt (concluded)
The following information is presented in compliance with the requirements
of US GAAP.
Bank and other loans -- long-term
Weighted average
interest rate at
December 31, December 31,
------------------- -------------------
2002 2001 2002 2001
------ ------ ------ ------
(%) ($ million)
US dollar........................................ 5 5 9,796 10,617
Sterling......................................... 4 4 26 19
Other currencies................................. 9 9 178 122
------ ------
10,000 10,758
====== ======
Bank and other loans -- short-term
December 31,
------------------
2002 2001
------ ------
($ million)
Current maturities of long-term debt................................... 2,535 1,993
Commercial paper....................................................... 4,853 4,634
Bank loans............................................................. 476 371
Other.................................................................. 2,138 2,020
------ ------
10,002 9,018
====== ======
Weighted average
interest rate
at December 31,
------------------
2002 2001
----- ------
(%)
Commercial paper....................................................... 1 2
Bank loans and other borrowings........................................ 4 4
US Industrial Revenue/Municipal bonds.................................. 1 2
F - 51
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 30 -- Accounts payable and accrued liabilities
December 31, 2002 December 31, 2001
------------------- -------------------
Within After Within After
1 year 1 year 1 year 1 year
------ ------ ------ ------
($ million)
Trade payables....................................... 17,454 -- 13,129 --
====== ====== ====== ======
Other accounts payable and accrued liabilities:
Joint ventures..................................... 22 -- 21 --
Associated undertakings............................ 287 12 268 4
Production taxes................................... 421 1,455 254 1,346
Taxation on profits................................ 3,420 -- 3,456 --
Social security.................................... 81 -- 63 --
Accruals and deferred income....................... 5,763 1,002 4,843 1,029
Dividends.......................................... 1,398 -- 1,289 --
Other.............................................. 7,369 986 5,201 707
------ ------ ------ ------
18,761 3,455 15,395 3,086
====== ====== ====== ======
Note 31 -- Other provisions
Unfunded Other
pension postretirement
Decommissioning Environmental plans benefits Other Total
--------------- ------------ ------- ---------- ------- -------
($ million)
At January 1, 2002............. 3,304 2,098 1,743 2,664 1,673 11,482
Exchange adjustments........... 250 28 362 -- 63 703
Acquisitions................... -- 20 1,051 36 -- 1,107
New provisions................. 308 312 356 276 333 1,585
Unwinding of discount.......... 106 52 -- -- 12 170
Change in discount rate........ 333 36 -- -- 6 375
Utilized/deleted............... (133) (424) (366) (214) (399) (1,536)
------- ------- ------- ------- ------- -------
At December 31, 2002 4,168 2,122 3,146 2,762 1,688 13,886
======= ======= ======= ======= ======= =======
The Group makes full provision for the future cost of decommissioning oil
and natural gas production facilities and related pipelines on a discounted
basis at the commencement of production. At December 31, 2002 the provision for
the costs of decommissioning these production facilities and pipelines at the
end of their economic lives was $4,168 million ($3,304 million at December 31,
2001). The provision has been estimated using existing technology, at current
prices and discounted using a real discount rate of 2.5% (2001 3%). These costs
are expected to be incurred over the next 30 years. While the provision is based
on the best estimate of future costs and the economic lives of the facilities
and pipelines, there is uncertainty regarding both the amount and timing of
incurring these costs. The estimated decommissioning costs on an undiscounted
basis are approximately $6,500 million.
F - 52
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 31 -- Other provisions (concluded)
Provisions for environmental remediation are made when a clean-up is
probable and the amount reasonably determinable. Generally this coincides with
commitment to a formal plan of action or, if earlier, on divestment or closure
of inactive sites. The provision for environmental liabilities at December 31,
2002 was $2,122 million ($2,098 million at December 31, 2001). The provision has
been estimated using existing technology, at current prices and discounted using
a real discount rate of 2.5% (2001 3%). These costs are expected to be incurred
over the next 10 years. 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 liability. The estimated environmental costs on an undiscounted basis
are approximately $2,300 million.
The Group also holds provisions for potential future awards under the
long-term performance plans, expected rental shortfalls on surplus properties
and sundry other liabilities. To the extent that these liabilities are not
expected to be settled within the next three years, the provisions are
discounted using a real discount rate of 2.5% (2001 3%).
Note 32 -- Capital and reserves
Paid
Share in Merger Other Retained
capital surplus reserve reserves earnings Total
--------- --------- --------- ---------- --------- ---------
($ million)
At January 1, 2002.......................... 5,629 4,014 26,983 223 37,518 74,367
Prior year adjustment -
change in accounting policy............... -- -- -- -- (9,206) (9,206)
--------- --------- --------- ---------- --------- ---------
Restated 5,629 4,014 26,983 223 28,312 65,161
Currency translation differences
(net of tax).............................. -- -- -- -- 3,333 3,333
Employee share schemes...................... 9 129 -- -- -- 138
ARCO........................................ 3 54 50 (50) -- 57
Repurchase of ordinary share capital........ (25) 25 -- -- (750) (750)
Qualifying Employee Share
Ownership Trust (QUEST)................... -- 21 -- -- (21) --
Profit for the year......................... -- -- -- -- 6,845 6,845
Dividends................................... -- -- -- -- (5,375) (5,375)
--------- --------- --------- ---------- --------- ---------
At December 31, 2002........................ 5,616 4,243 27,033 173 32,344 69,409
========= ========= ========= ========== ========= =========
The movements in the Group's share capital during the year are set out
above. All movements are quantified in terms of the number of BP shares issued
or repurchased.
Employee share schemes: During the year 33,820,750 ordinary shares were
issued under the BP, Amoco and Burmah Castrol employee share schemes.
ARCO: 12,894,348 ordinary shares were issued in respect of ARCO employee
share option schemes.
Repurchase of ordinary share capital: The Company purchased for
cancellation 100,140,987 ordinary shares for a total consideration of $750
million.
F - 53
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 33 -- Retained earnings
Retained earnings of $32,344 million ($28,312 million at December 31, 2001)
include the following amounts, the distribution of which is limited by statutory
or other restrictions:
December 31,
------------------
2002 2001
------ ------
($ million)
Parent company........................................................ 9,547 15,547
Subsidiary undertakings............................................... 5,620 2,696
Joint ventures and associated undertakings............................ 870 1,345
------ ------
16,037 19,588
====== ======
Cumulative net exchange losses (net of tax) of $1,209 million are included
in retained earnings ($4,542 million losses at December 31, 2001).
There were no unrealized currency translation differences for the year on
long-term borrowings used to finance equity investments in foreign currencies
(2001 nil and 2000 nil).
Note 34 -- Analysis of consolidated statement of cash flows
Reconciliation of historical cost profit before interest and tax to net cash
inflow from operating activities
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Historical cost profit before interest and tax................... 12,543 14,662 18,627
Depreciation and amounts provided................................ 10,401 8,858 7,526
Exploration expenditure written off.............................. 385 238 264
Share of profits of joint ventures and associated undertakings... (966) (1,194) (1,853)
Interest and other income........................................ (358) (478) (360)
(Profit) loss on sale of fixed assets and businesses
or termination of operations................................... (1,166) (537) (196)
Charge for provisions............................................ 1,277 1,008 702
Utilization of provisions........................................ (1,427) (1,119) (969)
(Increase) decrease in inventories............................... (1,521) 1,490 (1,449)
(Increase) decrease in receivables............................... (2,672) 1,989 (5,587)
Increase (decrease) in payables.................................. 2,846 (2,508) 3,711
-------- -------- ---------
Net cash inflow from operating activities........................ 19,342 22,409 20,416
======== ======== =========
F - 54
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 34 -- Analysis of consolidated statement of cash flows (concluded)
Financing
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Long-term borrowing........................................... (3,707) (1,296) (1,680)
Repayments of long-term borrowing............................. 2,369 2,602 2,353
Short-term borrowing.......................................... (9,849) (6,257) (4,120)
Repayments of short-term borrowing............................ 10,451 4,823 4,821
-------- -------- ---------
(736) (128) 1,374
Issue of ordinary share capital for employee share schemes.... (195) (181) (257)
Repurchase of ordinary share capital.......................... 750 1,281 2,001
Stamp duty reserve tax........................................ -- -- 295
-------- -------- ---------
Net cash (inflow) outflow..................................... (181) 972 3,413
======== ======== =========
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 $220 million (2001 $211 million inflow and
2000 $452 million outflow).
Commercial paper
Net movements in commercial paper are included within short-term borrowings
or repayment of short-term borrowings as appropriate.
Movement in net debt
Years ended December 31,
--------------------------------------------------------------------------------------------
2002 2001
-------------------------------------------- ------------------------------------------
Current Current
Finance asset Net Finance asset Net
debt Cash investments debt debt Cash investments debt
------- ------ ----------- ------ ------- ------ ----------- ------
($ million)
At January 1.......... (21,417) 1,358 450 (19,609) (21,190) 1,170 661 (19,359)
Exchange adjustments.. (64) 105 (15) 26 (8) (53) -- (61)
Acquisitions.......... (1,002) -- -- (1,002) (55) -- -- (55)
Net cash flow......... (736) 57 (220) (899) (128) 241 (211) (98)
Partnership interests
exchanged for BP
loan notes.......... 1,135 -- -- 1,135 -- -- -- --
Other movements....... 76 -- -- 76 (36) -- -- (36)
------ ------ ------ ------ ------ ------ ------ ------
At December 31........ (22,008) 1,520 215 (20,273) (21,417) 1,358 450 (19,609)
====== ====== ====== ====== ====== ====== ====== ======
F - 55
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 35 -- Employee share plans
Employee share options granted during the year 2002 2001 2000
------ ------ ------
(options thousands)
Savings related schemes................................. 9,719 7,901 7,930
Executive Directors' Incentive Plan..................... 2,068 2,598 709
BP Share Option Plan.................................... 66,771 58,208 50,461
------ ------ ------
78,558 68,707 59,100
====== ====== ======
The exercise prices for BP options granted during the year were
(pound)4.52/$6.78 (9,719,005 options) for savings-related and similar plans;
(pound)5.67/$8.51 (weighted average price) for Executive Directors' Incentive
Plan (2,068,026 options); and (pound)5.50/$8.25 (weighted average price) for
66,770,545 options granted under the BP Share Option Plan.
BP offers most of its employees the opportunity to acquire a shareholding
in the company through savings-related and/or matching share plan arrangements.
Such arrangements are now in place in nearly 80 countries. BP also uses
long-term performance plans (see Note 36) and the granting of share options as
elements of remuneration for executive directors and senior employees.
During 2002, share options were granted to the executive directors under
the Executive Directors' Incentive Plan (EDIP). For these options the option
exercise price was the market value (as determined in accordance with the plan
rules) on the grant date. The options granted to executive directors reflect
BP's performance in terms of total shareholder return (TSR), that is, share
price increase with all dividends reinvested, relative to the FTSE Global 100
group of companies over the three years preceding the grant. Options vest over
three years (one-third each after one, two and three years respectively) and
have a life of seven years after the grant.
Share options were also granted in 2002 under the BP Share Option Plan to
certain categories of employees. Subject to certain vesting requirements the
options are exercisable between the third and tenth anniversaries of the date of
grant. There are no performance conditions attaching to the options granted
during the year.
Under the BP ShareSave Plan (a savings-related share option plan) employees
save on a monthly basis over a three- or five-year period towards the purchase
of shares at a price fixed when the option is granted. The option price is
usually set at a 20% discount to the market price at the time of grant. The
option must be exercised within six months of maturity of the savings contract;
otherwise it lapses. The plan is run in the UK and a small number of other
countries.
Under the BP ShareMatch Plan, BP matches employees' own contributions of
shares, up to a predetermined limit. The shares are then held in trust for a
defined minimum period. The plan is run in the UK and in over 60 other
countries.
F - 56
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 35 -- Employee share plans (continued)
BP does not recognize an expense in respect of share options granted to
employees. If the fair value of options granted in any particular year is
estimated and this value amortized over the vesting period of the options, an
indication of the cost of granting options to employees can be made. The fair
value of each share option granted has been estimated using a Black-Scholes
option pricing model with the following assumptions:
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
Risk-free interest rate................................................ 4.0% 5.0% 6.0%
Expected volatility.................................................... 26% 26% 33%
Expected life in years................................................. 1 to 5 1 to 5 1 to 5
Expected dividend yield................................................ 3.75% 3.0% 3.0%
Weighted average fair value of options granted ($)..................... 1.64 2.05 2.33
The following table illustrates the effect on net income and earnings per
share if the Company had applied the fair value recognition provisions of FASB
Statement No. 123, Accounting for Stock-Based Compensation, to share based
employee compensation.
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Profit for the year applicable to ordinary shares,
as reported........................................................... 6,843 6,554 10,118
Deduct: Total stock-based employee compensation
expense determined under fair value based method
for all awards, net of related tax effects...................... (90) (102) (96)
------ ------ ------
Pro forma net income.................................................... 6,753 6,452 10,022
====== ====== ======
(cents)
Earnings per share
Basic -- as reported.................................................. 30.55 29.21 46.77
Basic -- pro forma.................................................... 30.15 28.76 46.32
Diluted -- as reported................................................ 30.41 29.04 46.46
Diluted -- pro forma.................................................. 30.01 28.58 46.01
The company sponsors a number of savings plans covering most US employees.
Under these plans, most employees may contribute up to 100% of their salary
subject to certain regulatory limits. Most employees are eligible for a
dollar-for-dollar Company matched contribution for the first 7% of eligible pay
contributed on a before-tax or after-tax basis, or a combination of both. The
precise arrangement may vary in certain business units. Company contributions
are initially invested in a fund primarily comprised of BP ADSs but employees
may transfer those amounts and may invest their own contributions in more than
200 investment options. The Company's contributions generally vest over a period
of three years. Company contributions to savings plans during the year were $125
million (2001 $125 million and 2000 $101 million).
F - 57
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 35 -- Employee share plans (continued)
An Employee Share Ownership Plan (ESOP) was established in 1997 to acquire
BP shares to satisfy future requirements of certain employee share plans. The
Company provides funding to the ESOP. The assets and liabilities of the ESOP are
recognized as assets and liabilities of the Company within the accounts. The
ESOP has waived its rights to dividends.
During 2002, the ESOP released 15,332,235 shares (2001 11,508,754 shares
and 2000 9,412,931 shares) for the matching share plans. The cost of shares
released for these plans has been charged in these accounts. At December 31,
2002, the ESOP held 18,673,675 shares (At December 31, 2001 34,005,910 shares).
BP has established a Qualifying Employee Share Ownership Trust (QUEST) to
support the UK ShareSave plan. During the year, contributions of $21 million
(2001 $36 million and 2000 $76 million) were made by the Company to the QUEST
which, together with option-holder contributions, were used by the QUEST to
subscribe for new ordinary shares at market price. The Company has transferred
the cost of this contribution directly to retained profits and the excess of the
subscription price over nominal value has increased the paid in surplus.
At December 31, 2002, all the 9,443,842 ordinary shares issued to the QUEST
had been transferred to employees exercising options under the UK ShareSave
plan. Under new legislation, the QUEST can no longer be used for ShareSave plans
after December 31, 2002.
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
(shares thousands)
Shares issued in respect of options exercised during the year:
Savings related schemes........................................... 10,412 8,842 13,709
BP, Amoco and Burmah Castrol executive share option plans......... 23,409 24,619 23,280
-------- -------- ---------
33,821 33,461 36,989
======== ======== =========
2002 2001 2000
-------- -------- ---------
Options outstanding at December 31:
BP options (shares thousands) ................. 410,986 373,858 342,509
Exercise period................................ 2003-2012 2002-2011 2001-2010
Price (pounds)................................. 1.50-6.40 1.29-6.40 1.29-6.40
Price (dollars)................................ 3.47-9.97 2.77-9.97 2.77-9.97
F - 58
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 35 -- Employee share plans (concluded)
The following table summarizes share option transactions under employee
share plans.
Years ended December 31,
--------------------------------------------------------------------------
2002 2001 2000
---------------------- ---------------------- ----------------------
Weighted Weighted Weighted
average average average
Number of exercise Number of exercise Number of exercise
shares price shares price shares price
---------- ---------- ---------- ---------- ---------- ----------
($) ($) ($)
Outstanding at January 1..... 373,857,979 6.20 343,218,324 5.61 323,161,387 4.95
Burmah Castrol............... -- -- -- -- 3,293,317 5.02
Reinstated................... 24,310 5.08 7,152 7.84 3,729 2.94
Granted...................... 78,557,576 8.07 68,706,983 8.13 59,100,161 8.17
Exercised.................... (34,130,302) 4.20 (33,592,964) 3.97 (37,029,467) 3.76
Cancelled.................... (7,323,384) 7.59 (4,481,516) 7.37 (5,310,803) 6.72
----------- ----------- -----------
Outstanding at December 31... 410,986,179 6.70 373,857,879 6.20 343,218,324 5.61
=========== =========== ===========
Exercisable at December 31... 239,241,597 241,268,277 229,987,199
=========== =========== ===========
Available for grant at
December 31................ 1,159,841,669 1,185,523,186 1,234,983,212
============= ============= =============
Options outstanding at December 31, 2002 will be exercisable between 2003
and 2012.
For the share options outstanding and exercisable at December 31, 2002 the
exercise price ranges and average remaining lives were:
Options outstanding Options exercisable
------------------------------------- -----------------------
Weighted Weighted Weighted
average average average
Number of remaining exercise Number of exercise
Shares life price shares price
---------- ---------- ---------- ---------- ----------
(years) ($) ($)
Range of exercise prices
$2.27 - $4.61......................... 86,078,177 2.02 3.98 84,902,527 3.97
$4.69 - $6.17......................... 86,230,486 4.53 5.60 81,239,138 5.57
$6.18 - $7.93......................... 75,990,971 5.44 7.56 34,820,867 7.84
$7.98 - $10.10........................ 162,686,545 8.21 8.32 38,279,065 8.28
----------- ---------- ---------- ----------- ----------
410,986,179 5.63 6.70 239,241,597 5.77
=========== ========== ========== =========== ==========
F - 59
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 36 -- Long term performance plans
During 2002, the Company operated two long-term performance plans: the
Executive Directors' Incentive Plan (EDIP) for executive directors and the Long
Term Performance Plan (LTPP) for senior executives. Executive directors
participated in the LTPP prior to 2002 or to their appointment as an executive
director. Both plans are incentive schemes under which the Company may award
shares to participants or fund the purchase of shares for participants if
long-term targets are met. Awards were made in 2002 in respect of the 1999-2001
LTPP.
The costs of potential future awards for both the EDIP and LTPP are accrued
over the three-year performance periods of each plan. The amount charged in 2002
was $51 million (2001 $80 million and 2000 $119 million). The value of awards
under the 1999-2001 LTPP made in 2002 was $125 million (1998-2000 LTPP made in
2001 $61 million and 1997-1999 LTPP made in 2000 $78 million).
Employee Share Ownership Plans (ESOPs) have been established to acquire BP
shares to satisfy any awards made to participants under the EDIP and LTPP and
then to hold them for the participants during the retention period of the plan.
In order to hedge the cost of potential future awards the ESOPs may, from time
to time over the performance period of the plans, purchase BP shares in the open
market. The Company provides funding to the ESOPs. The assets and liabilities of
the ESOPs are recognized as assets and liabilities of the Company within these
accounts. The ESOPs have waived their rights to dividends on shares held for
future awards.
At December 31, 2002 the ESOPs held 3,901,317 shares (at December 31, 2001,
7,673,056 shares) for potential future awards.
Note 37 -- Employee costs and numbers
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($million)
Employee costs
Wages and salaries............................................ 6,519 6,361 6,071
Social security costs......................................... 490 474 410
Pension and other postretirement benefit costs................ 440 427 187
------- ------- -------
7,449 7,262 6,668
======= ======= =======
At December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
Number of employees
Exploration and Production.................................... 16,800 16,550 16,000
Gas,Power and Renewables...................................... 4,400 4,200 3,400
Refining and Marketing (a).................................... 73,350 64,600 67,100
Chemicals..................................................... 17,900 21,950 17,600
Other businesses and corporate................................ 2,800 2,850 3,100
------- ------- -------
115,250 110,150 107,200
======= ======= =======
---------------
(a) Includes 30,250 (2001 28,500 and 2000 27,600) service station staff.
F - 60
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 37 -- Employee costs and numbers (concluded)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
Average number of employees
Year ended December 31, 2002
Exploration and Production................. 3,750 800 5,550 6,800 16,900
Gas, Power and Renewables.................. 500 850 1,400 1,550 4,300
Refining and Marketing .................... 10,200 21,700 28,650 11,550 72,100
Chemicals.................................. 3,200 5,250 6,650 5,150 20,250
Other businesses and corporate............. 1,250 -- 1,400 100 2,750
-------- -------- -------- -------- --------
18,900 28,600 43,650 25,150 116,300
======== ======== ======== ======== ========
Year ended December 31, 2001
Exploration and Production................. 3,550 750 5,700 6,200 16,200
Gas, Power and Renewables.................. 600 600 1,350 1,350 3,900
Refining and Marketing .................... 10,400 16,450 27,300 11,750 65,900
Chemicals.................................. 3,600 5,750 7,550 3,300 20,200
Other businesses and corporate............. 1,350 -- 1,500 100 2,950
-------- -------- -------- -------- --------
19,500 23,550 43,400 22,700 109,150
======== ======== ======== ======== ========
Year ended December 31, 2000
Exploration and Production................. 3,250 650 4,700 5,700 14,300
Gas, Power and Renewables.................. 550 450 1,350 850 3,200
Refining and Marketing .................... 9,600 13,700 25,800 10,700 59,800
Chemicals.................................. 3,700 4,600 8,100 1,400 17,800
Other businesses and corporate............. 1,100 -- 1,650 150 2,900
-------- -------- -------- -------- --------
18,200 19,400 41,600 18,800 98,000
======== ======== ======== ======== ========
Note 38 -- Directors' remuneration
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Total for all directors
Emoluments........................................................ 14 17 14
Ex gratia payment................................................. -- -- 1
Non-executive directors retiring in 2001.......................... -- 1 --
Gains made on the exercise of share options....................... -- -- 3
Amounts awarded under incentive schemes........................... 14 17 15
======== ======== =========
Emoluments
These amounts comprise fees paid to the non-executive chairman and
non-executive directors, and, for executive directors, salary and benefits
earned during the relevant financial year, plus bonuses awarded for the year.
F - 61
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 38 -- Directors' remuneration (concluded)
Pension contributions
Four executive directors participated in a non-contributory pension scheme
established for UK staff by a separate trust fund to which contributions are
made by BP based on actuarial advice. Two US executive directors participated in
the BP Retirement Accumulation Plan during 2002.
Non-executive directors retiring in 2002
The board did not make any payment to Sir Robert Wilson, the only
non-executive director retiring in 2002, in view of his limited length of
service.
Non-executive directors retiring in 2001
In accordance with Article 76 of the Company's Articles of Association, the
board exercised its discretion, following the retirement of each of those
non-executive directors retiring during 2001, to make an ex-gratia payment in
lieu of superannuation. The payments made were as follows: $86,400 to the Lord
Wright of Richmond, who retired after serving on the board since 1991; $21,600
to Richard Ferris, who retired after serving on the board of first Amoco and
then BP since 1981; and $17,280 to Ruth Block, who retired after serving on the
board of first Amoco and then BP since 1986. Richard Ferris and Ruth Block also
had accrued certain entitlements (which crystalized at the time of the merger
with Amoco Corporation) in the Amoco Restricted Stock Plan for Non-Executive
Directors ('the Plan'). The terms of the Plan provided that shares in respect of
service on the board of Amoco Corporation were to be held in the Plan until the
non-executive director retired at the normal retirement age (70), or in the case
of earlier retirement the board had a discretion to make an appropriate award
based upon length of service. Those directors who left the Plan at the time of
the merger had their entitlements paid out. The operation of the Plan for those
who remained fell to the discretion of the board of BP. Ruth Block retired at
age 70 and following her retirement the board released her shares held in the
Plan in respect of her service at Amoco Corporation to the value of $283,512 (as
at the date of their release). Richard Ferris retired at age 64 and the board
elected to waive restrictions on all those shares held in the Plan in respect of
his service at Amoco Corporation to the value of $293,716 (as at the date of
their release).
Office facilities for former chairmen and deputy chairmen
It is customary for the Company to make available to former chairmen and
deputy chairmen, who were previously employed executives, the use of office and
basic secretarial facilities following their retirement. The cost involved in
doing so is not significant.
Note 39 -- 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 - 62
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions
Most Group companies have pension plans, the forms and benefits of which
vary with conditions and practices in the countries concerned. Pension benefits
may be provided through defined contribution plans (money purchase schemes) or
defined benefit plans (final salary schemes). For defined contribution plans,
retirement benefits are determined by the value of funds arising from
contributions paid in respect of each employee. For defined benefit plans,
retirement benefits are based on the employees' pensionable salary and length of
service. Defined benefit plans may be externally funded or unfunded. The assets
of funded plans are generally held in separately administered trusts.
Contributions to funded defined benefit plans are based on advice from
independent actuaries using actuarial methods, the objective of which is to
provide adequate funds to meet pension obligations as they fall due. The
cumulative difference, since the adoption of Statement of Standard Accounting
Practice No. 24 'Accounting for Pension Costs' (SSAP24), between the
contributions paid by BP to the pension funds and the pension expense recorded
each year is reflected in the balance sheet. If the cumulative contributions
exceed pension expense the difference is shown as a prepayment on the balance
sheet. If the cumulative contributions are less than pension expense the
difference is shown as a provision on the balance sheet. For unfunded plans,
where assets are not held with the specific purpose of matching pension
obligations, the accrued liability for pension benefits is included within other
provisions. The majority of the Group's employees are members of defined benefit
plans. The principal plans are reviewed annually by the independent actuaries
and subject to a formal actuarial valuation at least every three years. The date
of the most recent actuarial reviews was December 31, 2002. The date of the
latest actuarial valuation for the UK plans was January 1, 2001 and for the US
plans and the unfunded plans in Europe was January 1, 2002.
The pension assumptions for the principal pension plans are set out below.
The assumptions used to evaluate accrued pension benefits at December 31 in any
year are used to determine pension expense for the following year, that is, the
assumptions at December 31, 2002 are used to determine the pension liabilities
at that date and the pension cost for 2003. This applies for all accounting
bases described in this note.
At December 31,
-------------------------------------
2002 2001 2000 1999
------ ------ ------ ------
(%)
UK plans:
Rate of return on assets........................... 6.25 6.0 6.5 6.5
Discount rate...................................... 6.25 6.0 6.5 6.5
Future salary increases............................ 4.0 4.5 5.0 5.0
Future pension increases........................... 2.5 2.5 3.0 3.0
Dividend growth.................................... n/a n/a n/a n/a
Other European plans:
Rate of return on assets........................... n/a n/a n/a n/a
Discount rate...................................... 5.75 6.2 6.2 6.2
Future salary increases............................ 4.0 3.2 3.2 3.2
Future pension increases........................... 2.4 2.0 2.1 2.1
Dividend growth.................................... n/a n/a n/a n/a
US plans:
Rate of return on assets........................... 8.0 10.0 10.0 10.0
Discount rate...................................... 6.75 7.25 7.5 7.5
Future salary increases............................ 4.0 4.0 4.0 4.0
Future pension increases........................... nil nil nil nil
Dividend growth.................................... n/a n/a n/a n/a
----------
n/a = not applicable
F - 63
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions (continued)
Pension costs for the principal plans have been derived using the projected
unit credit method and by amortizing surpluses and deficits on a straight line
basis over the average expected remaining service lives of the current
employees. An analysis of pension expense is set out below.
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Principal plans:
Regular cost..................................................... 450 397 364
Settlement, curtailment and special termination benefits......... 30 211 114
Other variations from regular cost............................... (520) (569) (611)
------ ------ ------
(40) 39 (133)
Other defined benefit plans........................................ 51 73 38
Defined contribution plans......................................... 153 155 220
------ ------ ------
164 267 125
====== ====== ======
At December 31, 2002, the market value and actuarial value of assets in the
Group's major externally funded pension plans and the market value and actuarial
value of those assets in relation to the benefits that had accrued to members of
those plans, after allowing for expected future increases in salaries, are set
out below.
UK US
----------------- ------------------
2002 2001 2002 2001
------ ------ ------- -------
Market value of plan assets ($ million).............. 15,138 16,880 4,206 5,625
-- as a percentage of accrued benefits............... 111% 132% 62% 91%
Actuarial value of plan assets ($ million)........... 19,074 17,654 5,818 6,315
-- as a percentage of accrued benefits............... 140% 139% 86% 103%
Prepayment ($ million)............................... 2,688 2,138 1,211 1,279
At December 31, 2002 the obligation for accrued benefits in respect of the
major unfunded plans in Europe was $3,191 million ($1,510 million at December
31, 2001). Of this amount, $2,645 million ($1,317 million at December 31, 2001)
has been provided in these accounts.
F - 64
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions (continued)
The assumed rate of investment return and discount rate have a significant
effect on the amounts reported. One percentage point change in these assumptions
for the principal plans would have the following effects:
1-Percentage 1-Percentage
point increase point decrease
------------- -------------
($ million)
Investment return:
Effect on pension expense in 2002.................................... (240) 240
Discount rate:
Effect on pension expense in 2002.................................... (320) 275
Effect on pension obligation at December 31, 2002.................... (3,575) 3,625
The group continues to account for pensions in accordance with SSAP 24.
However, there is a new standard, Financial Reporting Standard No. 17
'Retirement Benefits' (FRS 17), which changes the basis of accounting for
pensions and other postretirement benefits and requires certain disclosures in
the periods prior to adoption. The additional disclosures for the year ended
December 31, 2002 are shown in the following tables.
F - 65
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions (continued)
The expected long-term rates of return and market values of the various
categories of asset held by the significant defined benefit plans and the main
assumptions used to evaluate plan liabilities at December 31, on an FRS 17 basis
are set out below.
At December 31,
----------------------------------------------------
2002 2001
---------------------- ----------------------
Expected Expected
long-term long-term
rate of Market rate of Market
return value return value
------- ------- ------- -------
(%) ($ million) (%) ($ million)
UK plans:
Equities........................................ 7.5 10,815 7.5 12,228
Bonds........................................... 5.0 2,263 5.5 2,449
Property........................................ 6.5 1,352 6.5 1,057
Cash............................................ 4.0 708 4.5 1,146
------- -------
15,138 16,880
Present value of plan liabilities............... 14,822 12,746
------- -------
Surplus in the plans............................ 316 4,134
Deferred tax.................................... (95) (1,240)
------- -------
221 2,894
======= =======
Other European plans:
Equities........................................ n/a -- n/a --
Bonds........................................... n/a -- n/a --
Property........................................ n/a -- n/a --
Cash............................................ n/a -- n/a --
------- -------
-- --
Present value of plan liabilities............... 3,191 1,510
------- -------
Deficit in the plans............................ (3,191) (1,510)
Deferred tax.................................... 1,244 589
------- -------
(1,947) (921)
======= =======
US plans:
Equities........................................ 8.5 3,371 11.0 4,537
Bonds........................................... 5.5 720 7.0 942
Property........................................ 8.0 49 8.0 51
Cash............................................ 3.5 66 4.0 95
------- -------
4,206 5,625
Present value of plan liabilities............... 6,765 6,146
------- -------
Deficit in the plans............................ (2,559) (521)
Deferred tax.................................... 896 182
------- -------
(1,663) (339)
======= =======
F - 66
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions (continued)
At December 31,
------------------
2002 2001
------ ------
(%)
Other main assumptions for FRS17 disclosures as at December 31
UK plans
Discount rate for plan liabilities................................... 5.75 6.0
Rate of increase in salaries......................................... 4.0 4.5
Rate of increase for pensions in payment............................. 2.5 2.5
Rate of increase in deferred pensions................................ 2.5 2.5
Inflation............................................................ 2.5 2.5
Other European plans
Discount rate for plan liabilities................................... 5.75 6.2
Rate of increase in salaries......................................... 4.0 3.2
Rate of increase for pensions in payment............................. 2.4 2.0
Rate of increase in deferred pensions................................ 2.4 2.0
Inflation............................................................ 2.5 2.0
US plans
Discount rate for plan liabilities................................... 6.75 7.25
Rate of increase in salaries......................................... 4.0 4.0
Rate of increase for pensions in payment............................. nil nil
Rate of increase in deferred pensions................................ nil nil
Inflation............................................................ 2.5 3.0
F - 67
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions (continued)
Year ended December 31, 2002
----------------------------------
Other
UK European US
-------- -------- ---------
($ million)
Analysis of the amount charged to operating
profit on an FRS 17 basis
Current service cost................................................... 278 22 150
Past service cost...................................................... -- 4 38
Settlement, curtailment and special termination benefits............... -- (81) 75
------ ------ ------
Total operating charge................................................. 278 (55) 263
====== ====== ======
Analysis of the amount that would be credited (charged) to
other finance income on an FRS 17 basis
Expected return on pension plan assets................................. 1,204 -- 530
Interest on pension plan liabilities................................... (773) (155) (421)
------ ------ ------
Net return (expense)................................................... 431 (155) 109
====== ====== ======
Analysis of the amount that would be recognized in the
statement of total recognized gains and losses on an FRS 17 basis
Actual return less expected return on pension plan assets.............. (3,874) -- (1,305)
Experience gains and losses arising on the plan liabilities............ 212 (67) (290)
Change in assumptions underlying the present value of
the plan liabilities................................................. (480) (242) (343)
------ ------ ------
Actuarial loss recognized in statement of total
recognized gains and losses.......................................... (4,142) (309) (1,938)
====== ====== ======
Movement in surplus (deficit) during the the year on an FRS 17 basis
Surplus (deficit) in plans at January 1, 2002.......................... 4,134 (1,510) (521)
Movement in year:
Current service cost................................................. (278) (22) (150)
Past service cost.................................................... -- (4) (38)
Settlement, curtailment and special termination benefits............. -- 81 (75)
Acquisitions......................................................... -- (1,037) (14)
Other finance income................................................. 431 (155) 109
Actuarial loss....................................................... (4,142) (309) (1,938)
Employers' contributions............................................. 3 184 68
Exchange adjustments................................................. 168 (419) --
------ ------ ------
Surplus (deficit) in plans at December 31, 2002........................ 316 (3,191) (2,559)
====== ====== ======
F - 68
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions (continued)
At December 31, 2002
--------------------------------
Other
UK European US
-------- -------- ---------
History of experience gains and losses which would
be recognized on an FRS 17 basis
Difference between the expected and actual return on plan assets:
Amount ($ million)................................................... (3,874) n/a (1,305)
Percentage of plan assets............................................ (26)% n/a (31)%
Experience gains and losses on plan liabilities:
Amount ($ million)................................................... 212 (67) (290)
Percentage of the present value of the plan liabilities.............. 1% (2)% (4)%
Total amount recognized in statement of total recognized
gains and losses:
Amount ($ million)................................................... (4,142) (309) (1,938)
Percentage of the present value of the plan liabilities.............. (28)% (10)% (29)%
====== ====== ======
At December 31,
-------------------------------------------------
2002 2001
----------------------- -----------------------
Profit and Profit and
loss account loss account
Net assets reserve Net assets reserve
---------- ---------- ---------- ----------
($ million)
Group net assets and reserve reconciliation
As reported.......................................... 70,047 32,344 65,759 28,312
SSAP 24 pension prepayment (net of deferred tax)..... (2,669) (2,669) (2,328) (2,328)
SSAP 24 pension provision (net of deferred tax)...... 2,883 2,883 1,524 1,524
FRS 17 pension asset (net of deferred tax)........... 221 221 2,894 2,894
FRS 17 pension liability (net of deferred tax)....... (3,610) (3,610) (1,260) (1,260)
------ ------ ------ ------
Including FRS 17 pension assets and liabilities
(net of deferred tax).............................. 66,872 29,169 66,589 29,142
====== ====== ====== ======
F - 69
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- 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.
At December 31,
---------------------------------------
2002 2001 2000 1999
------ ------ ------ ------
(%)
Main assumptions for the principal plans
UK plans:
Discount rate........................................ 5.75 6.0 6.5 6.5
Expected return on plan assets....................... 7.0 6.0 6.5 6.5
Rate of increase in salaries......................... 4.0 4.5 5.0 5.0
Other European plans:
Discount rate........................................ 5.75 6.2 6.2 6.2
Expected return on plan assets....................... n/a n/a n/a n/a
Rate of increase in salaries......................... 4.0 3.2 3.2 3.2
US plans:
Discount rate........................................ 6.75 7.25 7.5 7.5
Expected return on plan assets....................... 8.0 10.0 10.0 10.0
Rate of increase in salaries......................... 4.0 4.0 4.0 4.0
----------
n/a = not applicable
Years ended December 31,
--------------------------------
Pension expense 2002 2001 2000
-------- -------- ---------
($ million)
Principal plans:
Service cost -- benefits earned during year.................... 450 397 364
Interest cost on projected benefit obligation.................. 1,349 1,309 1,211
Expected return on plan assets................................. (1,676) (1,717) (1,625)
Amortization of transition asset............................... (64) (66) (72)
Recognized net actuarial gain.................................. (206) (169) (203)
Recognized prior service cost.................................. 77 74 78
Curtailment and settlement (gains) losses...................... (46) 36 (119)
Special termination benefits................................... 76 175 233
------ ------ ------
(40) 39 (133)
Other defined benefit plans...................................... 51 73 38
Defined contribution plans....................................... 153 155 220
------ ------ ------
Total pension expense............................................ 164 267 125
====== ====== ======
F - 70
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Pensions (concluded)
UK Other European US
----------------- ----------------- -----------------
2002 2001 2002 2001 2002 2001
------ ------ ------ ------ ------ ------
($ million)
Benefit obligation at January 1........... 12,746 13,213 1,510 1,438 6,146 5,546
Service cost.............................. 278 255 22 12 150 130
Interest cost............................. 773 811 155 89 421 409
Plan amendments........................... -- -- 4 -- 38 16
Curtailments, settlements and
special termination benefits............ -- -- (81) -- 75 199
Actuarial (gain) loss..................... 269 (646) 309 (42) 672 536
Acquisitions.............................. -- -- 1,037 189 14 101
Plan participants' contributions.......... 29 26 -- -- -- --
Benefit payments.......................... (687) (546) (184) (101) (751) (791)
Exchange adjustment....................... 1,414 (367) 419 (75) -- --
------ ------ ------ ------ ------ ------
Benefit obligation at December 31......... 14,822 12,746 3,191 1,510 6,765 6,146
------ ------ ------ ------ ------ ------
Fair value of plan assets at January 1.... 16,880 19,617 -- -- 5,625 6,970
Actual return on plan assets.............. (2,671) (1,689) -- -- (736) (682)
Acquisitions.............................. -- -- -- -- -- 91
Plan participants' contributions.......... 29 26 -- -- -- --
Employers' contributions.................. 3 27 -- -- 68 46
Settlement payments....................... -- -- -- -- -- (9)
Benefit payments.......................... (687) (546) -- -- (751) (791)
Exchange adjustment....................... 1,584 (555) -- -- -- --
------ ------ ------ ------ ------ ------
Fair value of plan assets
at December 31.......................... 15,138 16,880 -- -- 4,206 5,625
------ ------ ------ ------ ------ ------
Funded status............................. 316 4,134 (3,191) (1,510) (2,559) (521)
Unrecognized transition (asset)
obligation.............................. (85) (154) 44 51 (1) (1)
Unrecognized net actuarial (gain) loss.... 1,766 (2,537) 499 141 3,699 1,777
Unrecognized prior service cost........... 691 695 3 1 72 24
------ ------ ------ ------ ------ ------
Net amount recognized..................... 2,688 2,138 (2,645) (1,317) 1,211 1,279
====== ====== ====== ====== ====== ======
Prepaid benefit cost
(accrued benefit liability)............... 2,688 2,138 (3,042) (1,454) (2,062) (147)
Intangible asset.......................... -- -- 13 26 124 86
Accumulated other
comprehensive income.................... -- -- 384 111 3,149 1,340
------ ------ ------ ------ ------ ------
2,688 2,138 (2,645) (1,317) 1,211 1,279
====== ====== ====== ====== ====== ======
F - 71
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 41 -- Other postretirement benefits
Certain Group companies in the USA provide postretirement healthcare and
life insurance benefits to their retired employees and dependants. The
entitlement to these benefits is usually based on the employee remaining in
service until retirement age and completion of a minimum period of service. The
plans are funded to a limited extent and the accrued net liability for
postretirement benefits is included within other provisions. The cost of
providing postretirement benefits is assessed annually by independent actuaries
using the projected unit credit method. The date of the latest actuarial
valuation was January 1, 2002.
The assumptions used in calculating the charge for postretirement benefits
are consistent with those shown in Note 40 for US pension plans.
The charge to income for postretirement benefits is as follows:
Years ended December 31,
----------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Service cost-- benefits earned during year.................... 37 31 25
Interest cost on projected benefit obligation................. 219 187 148
Expected return on plan assets................................ (4) (5) (5)
Recognized net actuarial (gain) loss.......................... 25 (6) (46)
Amortization of prior service cost recognized................. (4) (15) (20)
Curtailment (gain) loss....................................... 3 (32) (40)
------ ------ ------
Postretirement benefit expense................................ 276 160 62
====== ====== ======
At December 31, 2002 the independent actuaries have reassessed the
obligation for postretirement benefits at $4,326 million ($3,080 million at
December 31, 2001). The discount rate used to assess the obligation at December
31, 2002 was 6.75% (7.25% at December 31, 2001). The provision for
postretirement benefits at December 31, 2002 was $2,762 million ($2,664 million
at December 31, 2001).
Assumed future healthcare cost trend rate
Years ended December 31,
-----------------------------------------------------------------
2009
and
subsequent
2003 2004 2005 2006 2007 2008 years
------- ------- ------- ------- ------- ------- -------
Beneficiaries aged under 65................. 12% 11% 9% 8% 7% 6% 5%
Beneficiaries aged over 65.................. 15% 14% 12% 10% 8% 7% 6%
The assumed healthcare cost trend rate has a significant effect on the
amounts reported. A one-percentage-point change in the assumed healthcare cost
trend rate would have the following effects:
1-Percentage 1-Percentage
point increase point decrease
------------- -------------
($ million)
Effect on total of service and interest cost in 2002....................... 52 (41)
Effect on postretirement obligation at December 31, 2002................... 587 (476)
F - 72
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 41 -- Other postretirement benefits (continued)
As indicated in Note 40 -- Pensions, certain additional disclosures are
required by FRS 17 for the periods prior to adoption. The additional disclosures
for the year ended December 31, 2002 are set out below:
At December 31,
-----------------------------------------------
2002 2001
--------------------- ----------------------
Expected Expected
long-term long-term
rate of Market rate of Market
return value return value
--------- ------- --------- -------
(%) ($ million) (%) ($ million)
Equities........................................................ 8.5 24 11.0 30
Bonds........................................................... 5.5 9 7.0 11
------- -------
33 41
Present value of plan liabilities............................... 4,326 3,080
------- -------
Other postretirement benefit liability before deferred tax..... (4,293) (3,039)
Deferred tax.................................................... 1,503 1,124
------- -------
(2,790) (1,915)
======= =======
F - 73
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 41 -- Other postretirement benefits (continued)
Year ended
December 31,
2002
------------
($ million)
Analysis of the amount that would be charged to operating profit on an FRS 17 basis
Current service cost.................................................................... 37
Settlement, curtailment and special termination benefits................................ (78)
-----
Total operating charge.................................................................. (41)
=====
Analysis of the amount that would be charged to other finance costs
on an FRS 17 basis
Expected return on plan assets.......................................................... 4
Interest on plan liabilities............................................................ (219)
-----
Net return (expense).................................................................... (215)
=====
Analysis of the amount that would be recognized in the statement
of total recognized gains and losses on an FRS 17 basis
Actual return less expected return on plan assets....................................... (8)
Experience gains and losses arising on the plan liabilities............................. (89)
Change in assumptions underlying the present value of the plan liabilities.............. (1,165)
-----
Actuarial loss recognized in statement of total recognized gains and losses............. (1,262)
=====
Movement in deficit during the year on an FRS 17 basis
Deficit in plans at January 1, 2002..................................................... (3,039)
Movement in year:
Current service cost.................................................................. (37)
Settlement, curtailment and special termination benefits.............................. 78
Acquisitions.......................................................................... (36)
Other finance income.................................................................. (215)
Employers' contributions.............................................................. 218
Actuarial loss........................................................................ (1,262)
-----
Deficit in plans at December 31, 2002................................................... (4,293)
=====
Year ended
December 31,
2002
------------
History of experience gains and losses which would be recognized
on an FRS 17 basis
Difference between the expected and actual return on plan assets:
Amount ($ million).................................................................... (8)
Percentage of plan assets............................................................. (24)%
Experience gains and losses on plan liabilities:
Amount ($ million).................................................................... (95)
Percentage of the present value of the plan liabilities............................... (2)%
Total amount recognized in statement of total recognized gains and losses:
Amount ($ million).................................................................... (1,262)
Percentage of the present value of the plan liabilities............................... (29)%
=====
F - 74
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 41 -- Other postretirement benefits (concluded)
At December 31,
-------------------------------------------------
2002 2001
----------------------- -----------------------
Profit and Profit and
loss account loss account
Net assets reserve Net assets reserve
---------- ------------ ---------- ------------
($million)
Group net assets and reserve reconciliation
As reported............................................. 70,047 32,344 65,759 28,312
SSAP 24 other postretirement benefit provision
(net of deferred tax)................................. 1,795 1,795 1,732 1,732
FRS 17 other postretirement benefit provision
(net of deferred tax)................................. (2,790) (2,790) (1,914) (1,914)
------ ------ ------ ------
Including FRS 17 other postretirement benefits liability
(net of deferred tax)................................. 69,052 31,349 65,577 28,130
====== ====== ====== ======
Further information presented in compliance with the requirements of FASB
Statement of Financial Accounting Standards No. 132 -- 'Employers' Disclosures
about Pensions and Other Postretirement Benefits' is set out below.
2002 2001
------- -------
($ million)
Benefit obligation at January 1...................................... 3,080 2,562
Service cost......................................................... 37 31
Interest cost........................................................ 219 187
Plan amendments...................................................... -- 78
Settlement, curtailment and special termination benefits............. (78) (30)
Actuarial loss....................................................... 1,255 476
Acquisitions......................................................... 36 --
Benefit payments..................................................... (223) (224)
------ ------
Benefit obligation at December 31.................................... 4,326 3,080
------ ------
Fair value of plan assets at January 1............................... 41 49
Actual return on plan assets......................................... (4) (3)
Benefit payments..................................................... (4) (5)
------ ------
Fair value of plan assets at December 31............................. 33 41
------ ------
Funded status........................................................ (4,293) (3,039)
Unrecognized net actuarial (gain) loss............................... 1,580 349
Unrecognized prior service cost...................................... (49) 26
------ ------
Provision for postretirement benefits................................ (2,762) (2,664)
====== ======
F - 75
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 42 -- Joint ventures and associated undertakings
The significant joint ventures and associated undertakings of the BP Group
at December 31, 2002 are shown in Note 47. Transactions between these entities
and the Group are summarized below.
Sales to joint ventures and associated undertakings
2002 2001 2000
--------------------- --------------------- -------
Amount Amount
receivable at receivable at
Product Sales December 31 Sales December 31 Sales
------- ------- ------------ ------- ------------ -------
($ million) ($ million) ($ million)
Joint ventures
BP Solvay Polyethylene
Europe Chemicals feedstocks 308 55 24 24 --
Pan American Energy Crude oil 124 10 121 5 101
BP/Mobil Crude oil and products -- -- -- -- 2,933
Watson Cogeneration Natural gas 118 5 177 3 87
Associated undertakings
BP Solvay Polyethylene
North America Chemicals feedstocks 143 14 20 20 --
China American
Petrochemical Co. Chemicals feedstocks 117 22 92 2 --
Erdoelchemie Chemicals feedstocks -- -- 250 -- 718
Ruhrgas Natural gas 98 -- 124 11 78
Purchases from joint ventures and associated undertakings
2002 2001 2000
--------------------- --------------------- -------
Amount Amount
payable at payable at
Product Purchases December 31 Purchases December 31 Purchases
------- -------- ------------ -------- ------------ --------
($ million) ($ million) ($ million)
Joint ventures
Pan American Energy Crude oil 200 12 178 14 139
BP/Mobil Crude oil and products -- -- -- -- 1,762
Watson Cogeneration Electricity and steam 94 10 187 7 129
Associated undertakings
Abu Dhabi Marine Areas Crude oil 504 55 555 37 671
Abu Dhabi Petroleum Co. Crude oil 759 77 820 47 948
BP Solvay Polyethylene
North America Chemicals feedstocks 7 1 -- -- --
China American Petrochemicals 77 15 16 -- --
Petrochemical Co.
Erdoelchemie Petrochemicals -- -- 50 -- 114
Ruhrgas Natural gas 5 -- 18 -- --
F - 76
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 42 -- Joint ventures and associated undertakings (concluded)
On July 31, 2002 BP sold its 25.5% of Ruhrgas, previously an associated
undertaking. The sales and purchases shown above occurred in the period to July
31, 2002.
On November 1, 2001, the BP Solvay Polyethylene Europe joint venture was
formed. The sales figures for 2001 are from November 1, 2001.
On May 2, 2001 BP purchased the outstanding 50% of Erdoelchemie, previously
an associated undertaking. From that date it was fully consolidated. The sales
and purchases shown above occurred in the period to May 1, 2001.
The pan-European refining and marketing joint venture with ExxonMobil was
dissolved on August 1, 2000. Within the BP/Mobil joint venture, BP operated and
had a 70% interest in the fuels refining and marketing operation and had a 49%
interest in the lubricants business. On dissolution, BP acquired most of the
ExxonMobil assets used by the fuels refining and marketing operation. The sales
and purchases shown above occurred in the period to August 1, 2000.
Note 43 -- Contingent liabilities
There were contingent liabilities at December 31, 2002 in respect of
guarantees and indemnities entered into as part of the ordinary course of the
group's business. No material losses are likely to arise from such contingent
liabilities.
Approximately 200 lawsuits were filed in State and Federal Courts in Alaska
seeking compensatory and punitive damages arising out of the Exxon Valdez oil
spill in Prince William Sound in March 1989. Most of those suits named Exxon
(now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the
oil terminal at Valdez, and the other oil companies which own Alyeska. Alyeska
initially responded to the spill until the response was taken over by Exxon. BP
owns a 47% interest (reduced during 2001 from 50% by a sale of 3% to Phillips)
in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned
a further 20% interest in Alyeska following BP's combination with Atlantic
Richfield Company (ARCO). Alyeska and its owners have settled all 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 will defend the claims vigorously.
Since 1987, Atlantic Richfield Company (ARCO), a current subsidiary of BP,
has been named as a co-defendant in numerous lawsuits brought in the USA
alleging injury to persons and property caused by lead pigment in paint. The
majority of the lawsuits have been abandoned or dismissed as against ARCO. ARCO
(and in one case two of its affiliates) is named in these lawsuits as alleged
successor to International Smelting & Refining which, along with a predecessor
company, manufactured lead pigment during the period 1920-1946. Plaintiffs
include individuals and governmental entities. Several of the lawsuits purport
to be class actions. The lawsuits (depending on plaintiff) seek various remedies
including: compensation to lead-poisoned children; cost to find and remove lead
paint from buildings; medical monitoring and screening programmes; public
warning and education on lead hazards; reimbursement of government healthcare
costs and special education for lead-poisoned citizens; and punitive damages. No
case has been settled or tried to conclusion. While the amounts claimed could be
substantial and it is not possible to predict the outcome of these legal
actions, ARCO believes that it has valid defences and it intends to defend such
actions vigorously. Consequently, BP believes that the impact of these lawsuits
on the Group's results of operations, financial position or liquidity will not
be material.
F - 77
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- Contingent liabilities (concluded)
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 chemicals 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 are inherently difficult to estimate.
However, the estimated cost of known environmental obligations has been provided
in these accounts in accordance with the Group's accounting policies. While the
amounts of future costs could be significant and could be material to the
Group's results of operations in the period in which they are recognized, BP
does not expect these costs to have a material effect on the Group's financial
position or liquidity.
The Group generally restricts its purchase of insurance to situations where
this is required for legal or contractual reasons. This is because external
insurance is not considered an economic means of financing losses for the Group.
Losses will therefore be borne as they arise rather than being spread over time
through insurance premia with attendant transaction costs. The position is
reviewed periodically.
The parent company has issued guarantees under which amounts outstanding at
December 31, 2002 were $19,952 million (at December 31, 2001 $19,900 million),
including $19,896 million (at December 31, 2001 $19,843 million) in respect of
borrowings by its subsidiary undertakings and $56 million (at December 31, 2001
$57 million) in respect of liabilities of other third parties. In addition,
other group companies have issued guarantees under which amounts outstanding at
December 31, 2002 were $338 million (at December 31, 2001 $327 million) in
respect of borrowings of joint ventures and associated undertakings and $237
million (at December 31, 2001 $218 million) in respect of liabilities of other
third parties.
Note 44 -- Capital commitments
Authorized future capital expenditure by group companies for which
contracts had been placed at December 31, 2002 amounted to $5,966 million (at
December 31, 2001 $4,712 million).
F - 78
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 45 -- New accounting standard for deferred tax
With effect from January 1, 2002 BP has adopted Financial Reporting
Standard No.19 'Deferred Tax' (FRS 19). This standard generally requires that
deferred tax should be provided on a full liability basis rather than on a
restricted liability basis as required by Statement of Standard Accounting
Practice No.15 'Accounting for Deferred Tax'. The adoption of FRS 19 has been
treated as a change in accounting policy.
Under FRS 19 deferred tax is recognized in respect of all timing
differences that have originated but not reversed at the balance sheet date
where transactions or events have occurred at that date that will result in an
obligation to pay more, or a right to pay less, tax in the future. In
particular:
-- Provision is made for tax on gains arising from the disposal of fixed
assets that have been rolled over into replacement assets, only to the
extent that, at the balance sheet date, there is a binding agreement
to dispose of the replacement assets concerned. However, no provision
is made where, on the basis of all available evidence at the balance
sheet date, it is more likely than not that the taxable gain will be
rolled over into replacement assets and charged to tax only where the
replacement assets are sold.
-- Provision is made for deferred tax that would arise on remittance of
the retained earnings of overseas subsidiaries, joint ventures and
associated undertakings only to the extent that, at the balance sheet
date, dividends have been accrued as receivable.
Deferred tax assets are recognized only to the extent that it is considered
more likely than not that there will be suitable taxable profits from which the
underlying timing differences can be deducted.
Deferred tax is measured on an undiscounted basis at the tax rates that are
expected to apply in the periods in which timing differences reverse, based on
tax rates and laws enacted or substantively enacted at the balance sheet date.
As a consequence of adopting FRS 19, acquisitions have been restated as if
the new standard applied at that time. This leads to the creation of higher
deferred tax liabilities and greater amounts of goodwill on those acquisitions.
The change in accounting policy has resulted in a prior year adjustment.
Shareholders' funds at January 1, 2001 have been reduced by $7,832 million and
the tax charge for the year ended December 31, 2001 increased by $1,358 million.
The provision for deferred tax has been increased by $10,047 million at December
31, 2001. Profit for the current year has been reduced by approximately $750
million as a result of the change in accounting policy.
Comparative information for 2001 and 2000 has been restated to reflect the
changes described above.
F - 79
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 45 -- New accounting standard for deferred tax (continued)
Years ended December 31, As restated As reported
----------------------- ----------------------
2001 2000 2001 2000
---------- ---------- ---------- -----------
($ million)
Turnover.................................................. 175,389 161,826 175,389 161,826
Less: Joint ventures...................................... 1,171 13,764 1,171 13,764
------ ------ ------ ------
Group turnover............................................ 174,218 148,062 174,218 148,062
Replacement cost of sales................................. 147,001 120,797 146,893 120,720
Production taxes.......................................... 1,689 2,061 1,689 2,061
------ ------ ------ ------
Gross profit.............................................. 25,528 25,204 25,636 25,281
Distribution and administration expenses.................. 10,918 9,331 10,918 9,331
Exploration expense....................................... 480 599 480 599
------ ------ ------ ------
14,130 15,274 14,238 15,351
Other income.............................................. 694 805 694 805
------ ------ ------ ------
Group replacement cost operating profit................... 14,824 16,079 14,932 16,156
Share of profits of joint ventures........................ 443 808 443 808
Share of profits of associated undertakings............... 760 792 760 792
------ ------ ------ ------
Total replacement cost operating profit (a)............... 16,027 17,679 16,135 17,756
Profit (loss) on sale of businesses or termination
of operations........................................... (68) 132 (68) 132
Profit (loss) on sale of fixed assets..................... 603 88 603 88
------ ------ ------ ------
Replacement cost profit before interest and tax........... 16,562 17,899 16,670 17,976
Inventory holding gains (losses).......................... (1,900) 728 (1,900) 728
------ ------ ------ ------
Historical cost profit before interest and tax............ 14,662 18,627 14,770 18,704
Interest expense.......................................... 1,670 1,770 1,670 1,770
------ ------ ------ ------
Profit before taxation.................................... 12,992 16,857 13,100 16,934
Taxation.................................................. 6,375 6,648 5,017 4,972
------ ------ ------ ------
Profit after taxation..................................... 6,617 10,209 8,083 11,962
Minority shareholders' interest -- equity................. 61 89 73 92
------ ------ ------ ------
Profit for the year*...................................... 6,556 10,120 8,010 11,870
Dividend requirements on preference shares*............... 2 2 2 2
------ ------ ------ ------
Profit for the year applicable to ordinary shares*........ 6,554 10,118 8,008 11,868
====== ====== ====== ======
Profit per ordinary share -- cents
Basic..................................................... 29.21 46.76 35.70 54.85
Diluted................................................... 29.04 46.46 35.48 54.48
====== ====== ====== ======
Dividends per ordinary share-- cents...................... 22.0 20.5 22.0 20.5
====== ====== ====== ======
Average number outstanding of 25 cents ordinary
shares (in thousands)................................... 22,435,737 21,638,280 22,435,737 21,638,280
========== ========== ========== ==========
---------------
* 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 50.
F - 80
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 45 -- New accounting standard for deferred tax (concluded)
As restated As reported
---------------------- ----------------------
2001 2000 2001 2000
--------- --------- --------- ----------
($ million)
(a) Total replacement cost operating profit
Exploration and Production....................... 12,361 13,972 12,417 14,012
Gas, Power and Renewables (b).................... 488 532 521 571
Refining and Marketing........................... 3,573 3,486 3,625 3,523
Chemicals........................................ 128 760 128 760
Other businesses and corporate (b)............... (523) (1,071) (556) (1,110)
------ ------ ------ ------
16,027 17,679 16,135 17,756
====== ====== ====== ======
(b) Restatement is related to the transfer of the solar, renewables and
alternative fuels activities from Other businesses and corporate to Gas,
Power and Renewables - see Note 46.
Balance sheet at December 31, 2001 Restated Reported
-------- --------
($ million)
Fixed assets
Intangible assets........................................... 16,489 15,593
Tangible assets............................................. 77,410 77,410
Investments................................................. 11,963 12,047
------ ------
105,862 105,050
------ ------
Current assets..................................................... 36,108 36,108
Creditors - amounts falling due within one year.................... 37,614 37,614
------ ------
Net current liabilities............................................ (1,506) (1,506)
------ ------
Total assets less current liabilities.............................. 104,356 103,544
Creditors - amounts falling due after more than one year........... 15,413 15,413
Provisions for liabilities and charges
Deferred taxation............................................. 11,702 1,655
Other provisions.............................................. 11,482 11,482
------ ------
Net assets......................................................... 65,759 74,994
Minority shareholders' interest.................................... 598 627
------ ------
BP shareholders' interest........................................... 65,161 74,367
====== ======
Statement of total recognized gains and losses
Restated Reported
-------- --------
($ million)
For the year ended December 31, 2001
Profit for the year................................................ 6,556 8,010
Currency translation differences (net of tax)...................... (828) (908)
------ ------
Total recognized gains and losses.................................. 5,728 7,102
====== ======
For the year ended December 31, 2000
Profit for the year................................................ 10,120 11,870
Currency translation differences (net of tax)...................... (2,340) (2,508)
------ ------
Total recognized gains and losses.................................. 7,780 9,362
====== ======
F - 81
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 46 -- Transfer of solar, renewables and alternative fuels activities
With effect from January 1, 2002, the solar, renewables and alternative
fuels activities were transferred from Other Businesses and Corporate to Gas and
Power. To reflect this transfer, Gas and Power has been renamed Gas, Power and
Renewables from the same date. Comparative information for 2001 and 2000 has
been restated to reflect this change.
As restated As reported
------------------------- -------------------------
Gas, Power Other Gas, Power Other
and businesses and businesses
Renewables and corporate Renewables and corporate
---------- ------------- ---------- -------------
($ million)
December 31, 2001
Turnover.............................................. 39,442 549 39,208 783
-------- -------- -------- --------
Group replacement cost operating profit............... 304 (598) 337 (631)
Joint ventures........................................ -- -- -- --
Associated undertakings............................... 184 75 184 75
-------- -------- -------- --------
Total replacement cost operating profit............... 488 (523) 521 (556)
Exceptional items..................................... -- 166 (1) 167
-------- -------- -------- --------
Replacement cost profit before interest and tax....... 488 (357) 520 (389)
-------- -------- -------- --------
Inventory holding gains (losses)...................... (81) -- (81) --
-------- -------- -------- --------
Capital expenditure and acquisitions.................. 492 430 359 563
-------- -------- -------- --------
Operating capital employed............................ 3,125 1,489(a) 2,764 1,850
-------- -------- -------- --------
Tangible assets....................................... 1,644 1,351 1,419 1,576
-------- -------- -------- --------
Number of employees -- year end....................... 4,200 2,850 1,950 5,100
-------- -------- -------- --------
Number of employees -- average........................ 3,900 2,950 1,800 5,050
======== ======== ======== ========
December 31, 2000
Turnover.............................................. 21,203 59 21,013 249
-------- -------- -------- --------
Group replacement cost operating profit............... 370 (1,113) 409 (1,152)
Joint ventures........................................ -- -- -- --
Associated undertakings............................... 162 42 162 42
-------- -------- -------- --------
Total replacement cost operating profit............... 532 (1,071) 571 (1,110)
Exceptional items..................................... 2 213 1 214
-------- -------- -------- --------
Replacement cost profit before interest and tax....... 534 (858) 572 (896)
-------- -------- -------- --------
Inventory holding gains (losses)...................... 11 -- 11 --
-------- -------- -------- --------
Number of employees -- year end... ................... 3,400 3,100 1,600 4,900
-------- -------- -------- --------
Number of employees -- average........................ 3,200 2,900 1,500 4,600
======== ======== ======== ========
---------------
(a) Before FRS 19 Deferred Tax restatement of $84 million.
F - 82
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Summarized financial information on joint ventures and associated
undertakings
A summarized statement of income and assets and liabilities based on latest
information available, with respect to the Group's equity accounted joint
ventures and associated undertakings, is set out below:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Sales and other operating revenue........................... 22,457 27,503 45,335
Gross profit................................................ 4,180 5,164 8,968
Profit for the year......................................... 2,049 3,105 4,219
======== ======== =========
December 31,
------------------
2002 2001
------ ------
($ million)
Fixed and other assets...................................... 17,350 25,175
Current assets.............................................. 6,895 14,402
------ ------
24,245 39,577
Current liabilities......................................... (6,344) (10,022)
Noncurrent liabilities...................................... (6,894) (9,365)
------ ------
Net assets.................................................. 11,007 20,190
====== ======
F - 83
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Summarized financial information on associated undertakings and joint
ventures (concluded)
The more important joint ventures and associated undertakings of the Group
at December 31, 2002 and the percentage of ordinary share capital owned or joint
venture interest (to nearest whole number) are:
Country of
% incorporation Principal activities
-- ---------- ----------------
Associated undertakings
Abu Dhabi
Abu Dhabi Marine Areas...................... 37 England Crude oil production
Abu Dhabi Petroleum Co...................... 24 England Crude oil production
Russia
Rusia Petroleum............................. 29 Russia Exploration and production
Sidanco..................................... 25 Russia Integrated oil operations
Taiwan
China American Petrochemical Co............. 50 Taiwan Chemicals
USA
BP Solvay Polyethylene North America........ 49 USA Chemicals
Principal place
% of business Principal activities
-- ---------- ----------------
Joint ventures
BP Solvay Polyethylene Europe............... 50 Europe Chemicals
CaTO Finance Partnership.................... 50 UK Finance
Lukarco..................................... 46 Kazakhstan Exploration and production, pipelines
Malaysia - Thailand Joint Development Area.. 25 Thailand Exploration and Production
Pan American Energy......................... 60 Argentina Exploration and Production
Unimar Company Texas (Partnership).......... 50 Indonesia Exploration and Production
Watson Cogeneration......................... 51 USA Power generation
F - 84
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 48 -- Oil and natural gas exploration and production activities (a)
Capitalized costs at December 31
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
2002
Gross capitalized costs:
Proved properties.............................. 26,804 4,029 46,996 24,604 102,433
Unproved properties............................ 294 179 1,045 3,669 5,187
------ ------ ------ ------ ------
27,098 4,208 48,041 28,273 107,620
Accumulated depreciation......................... 16,394 2,591 22,613 12,653 54,251
------ ------ ------ ------ ------
Net capitalized costs............................ 10,704 1,617 25,428 15,620 53,369
====== ====== ====== ====== ======
2001
Gross capitalized costs:
Proved properties.............................. 23,627 2,912 42,868 21,488 90,895
Unproved properties............................ 313 120 1,426 3,677 5,536
------ ------ ------ ------ ------
23,940 3,032 44,294 25,165 96,431
Accumulated depreciation......................... 13,320 1,883 19,508 10,980 45,691
------ ------ ------ ------ ------
Net capitalized costs............................ 10,620 1,149 24,786 14,185 50,740
====== ====== ====== ====== ======
2000
Gross capitalized costs:
Proved properties.............................. 24,319 2,683 38,494 19,607 85,103
Unproved properties............................ 482 73 1,754 3,449 5,758
------ ------ ------ ------ ------
24,801 2,756 40,248 23,056 90,861
Accumulated depreciation......................... 13,182 1,797 18,204 8,933 42,116
------ ------ ------ ------ ------
Net capitalized costs............................ 11,619 959 22,044 14,123 48,745
====== ====== ====== ====== ======
F - 85
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 48 -- Oil and natural gas exploration and production activities (a)
(continued)
Costs incurred for the year ended December 31
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
2002
Acquisition of properties:
Proved......................................... -- 4 -- 59 63
Unproved....................................... -- -- 29 8 37
------ ------ ------ ------ ------
-- 4 29 67 100
Exploration and appraisal costs (b).............. 28 68 441 571 1,108
Development costs................................ 895 219 3,618 2,503 7,235
------ ------ ------ ------ ------
Total costs...................................... 923 291 4,088 3,141 8,443
====== ====== ====== ====== ======
2001
Acquisition of properties:
Proved......................................... -- -- -- 47 47
Unproved....................................... 4 -- 20 193 217
------ ------ ------ ------ ------
4 -- 20 240 264
Exploration and appraisal costs (b).............. 109 80 295 618 1,102
Development costs................................ 930 271 3,723 1,934 6,858
------ ------ ------ ------ ------
Total costs...................................... 1,043 351 4,038 2,792 8,224
====== ====== ====== ====== ======
2000
Acquisition of properties:
Proved......................................... 2,838 -- 8,962 2,036 13,836
Unproved....................................... 14 -- 499 1,786 2,299
------ ------ ------ ------ ------
2,852 -- 9,461 3,822 16,135
Exploration and appraisal costs (b).............. 86 67 676 466 1,295
Development costs................................ 808 153 2,328 1,274 4,563
------ ------ ------ ------ ------
Total costs...................................... 3,746 220 12,465 5,562 21,993
====== ====== ====== ====== ======
F - 86
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 48 -- Oil and natural gas exploration and production activities (a)
(continued)
Results of operations for the year ended December 31
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
2002
Turnover (c):
Third parties.................................. 2,249 465 1,321 2,497 6,532
Sales between businesses....................... 3,169 594 7,857 4,952 16,572
------ ------ ------ ------ ------
5,418 1,059 9,178 7,449 23,104
------ ------ ------ ------ ------
Exploration expense.............................. 27 47 258 312 644
Production costs................................. 662 101 1,419 950 3,132
Production taxes................................. 279 7 288 670 1,244
Other costs (d).................................. 315 36 1,558 1,494 3,403
Depreciation..................................... 1,875 154 3,129 1,544 6,702
------ ------ ------ ------ ------
3,158 345 6,652 4,970 15,125
------ ------ ------ ------ ------
Profit before taxation (e)....................... 2,260 714 2,526 2,479 7,979
Allocable taxes.................................. 1,375 412 890 887 3,564
------ ------ ------ ------ ------
Results of operations ........................... 885 302 1,636 1,592 4,415
====== ====== ====== ====== ======
2001
Turnover (c):
Third parties.................................. 2,979 564 1,642 2,581 7,766
Sales between businesses....................... 3,003 462 9,645 4,892 18,002
------ ------ ------ ------ ------
5,982 1,026 11,287 7,473 25,768
------ ------ ------ ------ ------
Exploration expense.............................. 14 22 256 188 480
Production costs................................. 878 91 1,379 915 3,263
Production taxes................................. 559 17 384 688 1,648
Other costs (d).................................. 25 33 1,743 1,534 3,335
Depreciation..................................... 1,353 115 3,090 1,115 5,673
------ ------ ------ ------ ------
2,829 278 6,852 4,440 14,399
------ ------ ------ ------ ------
Profit before taxation (e)....................... 3,153 748 4,435 3,033 11,369
Allocable taxes.................................. 1,046 306 1,463 1,201 4,016
------ ------ ------ ------ ------
Results of operations ........................... 2,107 442 2,972 1,832 7,353
====== ====== ====== ====== ======
F - 87
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 48 -- Oil and natural gas exploration and production activities (a)
(continued)
Results of operations for the year ended December 31 (continued)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
2000
Turnover (c):
Third parties.................................. 3,538 926 4,242 2,446 11,152
Sales between businesses....................... 3,191 138 6,755 5,593 15,677
------ ------ ------ ------ ------
6,729 1,064 10,997 8,039 26,829
------ ------ ------ ------ ------
Exploration expense.............................. 36 42 257 264 599
Production costs................................. 772 86 1,311 786 2,955
Production taxes................................. 641 6 437 911 1,995
Other costs (d).................................. 74 6 1,624 1,889 3,593
Depreciation..................................... 1,453 98 2,446 748 4,745
------ ------ ------ ------ ------
2,976 238 6,075 4,598 13,887
------ ------ ------ ------ ------
Profit before taxation (e)....................... 3,753 826 4,922 3,441 12,942
Allocable taxes.................................. 1,127 355 1,712 1,376 4,570
------ ------ ------ ------ ------
Results of operations ........................... 2,626 471 3,210 2,065 8,372
====== ====== ====== ====== ======
----------
The Group's share of joint ventures' and associated undertakings' results
of operations in 2002 was a profit of $372 million (2001 $246 million and 2000
$293 million) after deducting a tax charge of $110 million (2001 $138 million
tax charge and 2000 $97 million tax charge).
The Group's share of joint ventures' and associated undertakings' net
capitalized costs at December 31, 2002 was $4,350 million (December 31, 2001
$3,325 million and December 31, 2000 $3,354 million).
The Group's share of joint ventures' and associated undertakings' costs
incurred in 2002 was $850 million (2001 $419 million and 2000 $1,490 million).
(a) This note relates to the requirements contained within the UK Statement of
Recommended Practice 'Accounting for Oil and Gas Exploration, Development,
Production and Decommissioning Activities'. Mid-stream activities of
natural gas gathering and distribution and the operation of the main
pipelines and tankers are excluded. The main mid-stream activities are the
Alaskan transportation facilities, the Forties Pipeline system and the
Central Area Transmission System. The Group's share of joint ventures' and
associated undertakings' activities is excluded from the tables and
included in the footnotes, with the exception of the Abu Dhabi operations
which are included in the income and expenditure items above. Profits
(losses) on sale of fixed assets and businesses or termination of
operations relating to the oil and natural gas exploration and production
activities, which have been accounted as exceptional items, are also
excluded.
(b) Includes exploration and appraisal drilling expenditure and licence
acquisition costs which are capitalized within intangible fixed assets and
geological and geophysical exploration costs which are charged to income as
incurred.
(c) Turnover represents sales of production excluding royalty oil where royalty
is payable in kind.
F - 88
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 48 -- Oil and natural gas exploration and production activities (a)
(concluded)
(d) Includes cost of royalty oil not taken in kind, property taxes and other
government take.
(e) The exploration and production total replacement cost operating profit
comprises:
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
Year ended December 31, 2002
Exploration and production activities
-- Group (as above)..................... 2,260 714 2,526 2,479 7,979
-- Equity-accounted entities............ -- -- 16 466 482
Midstream activities.................... 266 -- 293 186 745
-------- -------- -------- -------- --------
Total replacement cost operating profit 2,526 714 2,835 3,131 9,206
======== ======== ======== ======== ========
Year ended December 31, 2001
Exploration and production activities
-- Group (as above)..................... 3,153 748 4,435 3,033 11,369
-- Equity-accounted entities............ -- -- -- 384 384
Midstream activities.................... 271 -- 138 199 608
-------- -------- -------- -------- --------
Total replacement cost operating profit 3,424 748 4,573 3,616 12,361
======== ======== ======== ======== ========
Year ended December 31, 2000
Exploration and production activities
-- Group (as above)..................... 3,753 826 4,922 3,441 12,942
-- Equity-accounted entities............ -- -- -- 390 390
Midstream activities.................... 290 -- 152 198 640
-------- -------- -------- -------- --------
Total replacement cost operating profit 4,043 826 5,074 4,029 13,972
======== ======== ======== ======== ========
Note 49 -- Business and geographical analysis
BP has four reportable operating segments -- Exploration and Production;
Gas, Power and Renewables; Refining and Marketing; and Chemicals. Exploration
and Production's activities include oil and natural gas exploration and field
development and production (upstream activities), together with pipeline
transportation and natural gas processing (midstream activities). Gas, Power and
Renewables activities include marketing and trading of natural gas, natural gas
liquids, new market development, LNG and solar and renewables. 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 - 89
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 49 -- Business and geographical analysis (continued)
By business
Gas Other
Exploration Power Refining businesses
and and and and
Production Renewables Marketing Chemicals corporate(a) Eliminations Total
----------- ---------- --------- --------- --------- ------------ -----
($ million)
2002
Group turnover -- third parties...... 7,197 36,037 122,470 12,507 510 -- 178,721
-- sales between
businesses(b)...... 18,556 1,320 3,366 557 -- (23,799) --
------- ------- ------- ------- ------- ------- -------
25,753 37,357 125,836 13,064 510 (23,799) 178,721
------- ------- ------- ------- ------ -------
Share of sales by joint ventures..... 1,465
---------
180,186
---------
Equity accounted income (c).......... 611 107 204 (12) 52 962
------- ------- ------- ------- ------ -------
Total replacement cost operating
profit (loss)(d)................... 9,206 354 872 515 (701) 10,246
Exceptional items (e)................ (726) 1,551 613 (256) (14) 1,168
Inventory holding gains (losses)..... 3 51 1,049 26 -- 1,129
------- ------- ------- ------- ------ -------
Historical cost profit (loss) before
interest and tax................... 8,483 1,956 2,534 285 (715) 12,543
------- ------- ------- ------- ------ -------
Total assets (f)..................... 72,801 6,927 55,815 16,595 6,987 159,125
Operating capital employed (g)....... 62,117 2,642 31,006 12,631 490 108,886
Depreciation and amounts provided(h). 6,799 117 2,658 749 78 10,401
Capital expenditure and acquisitions(i) 9,699 408 7,753 823 428 19,111
2001
Group turnover -- third parties..... 8,569 36,488 117,330 11,282 549 -- 174,218
-- sales between
businesses (b).... 19,660 2,954 2,903 233 -- (25,750) --
------- ------- ------- ------- ------- ------- -------
28,229 39,442 120,233 11,515 549 (25,750) 174,218
------- ------- ------- ------- ------- -------
Share of sales by joint ventures.... 1,171
---------
175,389
---------
Equity accounted income (c)......... 559 184 278 107 75 1,203
------- ------- ------- ------- ------- -------
Total replacement cost operating
profit(loss) (d).................. 12,361 488 3,573 128 (523) 16,027
Exceptional items (e)............... 195 -- 471 (297) 166 535
Inventory holding gains (losses).... (6) (81) (1,583) (230) -- (1,900)
------- ------- ------- ------- ------ -------
Historical cost profit (loss) before
interest and tax.................. 12,550 407 2,461 (399) (357) 14,662
------- ------- ------- ------- ------ -------
Total assets (f).................... 70,017 5,775 43,553 15,098 7,527 141,970
Operating capital employed (g)...... 60,146 3,125 25,319 11,996 1,405 101,991
Depreciation and amounts provided (h) 6,043 67 2,302 588 96 9,096
Capital expenditure and acquisitions(i) 8,861 492 2,415 1,926 430 14,124
F - 90
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 49 -- Business and geographical analysis (continued)
By business (continued)
Gas Other
Exploration Power Refining businesses
and and and and
Production Renewables Marketing Chemicals corporate(a) Eliminations Total
----------- ---------- --------- --------- --------- ------------ -----
($ million)
2000
Group turnover-- third parties...... 14,155 20,857 101,960 11,031 59 -- 148,062
-- sales between
businesses (b)..... 16,787 346 5,923 216 -- (23,272) --
------- ------- ------- ------- ------- ------- -------
30,942 21,203 107,883 11,247 59 (23,272) 148,062
------- ------- ------- ------- ------ -------
Share of sales by joint ventures.... 13,764
---------
161,826
---------
Equity accounted income (c)......... 613 162 599 184 42 1,600
------- ------- ------- ------- ------ -------
Total replacement cost operating
profit (loss) (d)................. 13,972 532 3,486 760 (1,071) 17,679
Exceptional items (e)............... 119 2 98 (212) 213 220
Inventory holding gains (losses).... 4 11 620 93 -- 728
------- ------- ------- ------- ------ -------
Historical cost profit (loss) before
interest and tax.................. 14,095 545 4,204 641 (858) 18,627
------- ------- ------- ------- ------ -------
Total assets (f).................... 66,405 6,997 46,288 13,674 11,498 144,862
Operating capital employed (g)...... 57,001 3,208 28,307 11,008 2,094 101,618
Depreciation and amounts provided (h) 5,196 55 1,752 704 83 7,790
Capital expenditure and acquisitions(i) 6,383 376 8,693 1,585 30,576 47,613
By geographical area
Rest of Rest of
UK(j) Europe USA World Eliminations Total
-------- -------- -------- -------- ------------ ------
($ million)
2002
Group turnover -- third parties (k)........ 34,075 38,538 78,282 27,826 -- 178,721
-- sales between areas...... 14,673 7,980 2,099 6,575 (31,327) --
------- ------- ------- ------- ------- -------
48,748 46,518 80,381 34,401 (31,327) 178,721
------- ------- ------- ------- -------
Share of sales by joint ventures............ 129 298 236 802 -- 1,465
-------
180,186
-------
Equity accounted income (c)................. (5) 131 225 611 962
------- ------- ------- ------- -------
Total replacement cost operating
profit (d)................................ 1,696 1,703 2,890 3,957 10,246
Exceptional items (e)....................... (88) 1,817 (242) (319) 1,168
Inventory holding gains (losses)............ 88 283 640 118 1,129
------- ------- ------- ------- -------
Historical cost profit before
interest and tax.......................... 1,696 3,803 3,288 3,756 12,543
------- ------- ------- ------- -------
Total assets (f)............................ 33,016 25,012 63,982 37,115 159,125
Operating capital employed (g).............. 20,949 11,877 48,256 27,804 108,886
Depreciation and amounts provided (h)....... 2,821 867 4,780 1,933 10,401
Capital expenditure and acquisitions (i).... 1,637 6,556 6,095 4,823 19,111
F - 91
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 49 -- Business and geographical analysis (continued)
By geographical area (continued)
Rest of Rest of
UK(j) Europe USA World Eliminations Total
-------- -------- -------- -------- ------------ ------
($ million)
2001
Group turnover -- third parties (k)......... 34,151 29,098 83,757 27,212 -- 174,218
-- sales between areas....... 13,467 7,603 939 6,699 (28,708) --
------- ------- ------- ------- ------- -------
47,618 36,701 84,696 33,911 (28,708) 174,218
------- ------- ------- ------- -------
Share of sales by joint ventures............ 13 30 318 810 -- 1,171
-------
175,389
-------
Equity accounted income (c)................. 11 235 309 648 1,203
------- ------- ------- ------- -------
Total replacement cost operating
profit (d)................................ 2,668 1,814 6,941 4,604 16,027
Exceptional items (e)....................... (319) 33 289 532 535
Inventory holding gains (losses)............ (225) (444) (1,014) (217) (1,900)
------- ------- ------- ------- -------
Historical cost profit before
interest and tax.......................... 2,124 1,403 6,216 4,919 14,662
------- ------- ------- ------- -------
Total assets (f)............................ 29,951 15,287 63,150 33,582 141,970
Operating capital employed (g).............. 19,477 7,346 45,188 29,980 101,991
Depreciation and amounts provided (h)....... 2,159 513 4,937 1,487 9,096
Capital expenditure and acquisitions (i).... 2,128 1,787 6,160 4,049 14,124
2000
Group turnover -- third parties (k)...... 34,430 18,642 70,255 24,735 -- 148,062
-- sales between areas.... 10,970 1,911 829 6,279 (19,989) --
------- ------- ------- ------- ------- -------
45,400 20,553 71,084 31,014 (19,989) 148,062
------- ------- ------- ------- -------
Share of sales by joint ventures............ 3,314 12,316 270 686 (2,822) 13,764
-------
161,826
-------
Equity accounted income (c)................. 144 525 290 641 1,600
------- ------- ------- ------- -------
Total replacement cost operating
profit (d)................................ 3,773 2,013 7,219 4,674 17,679
Exceptional items (e)....................... 12 (19) 459 (232) 220
Inventory holding gains (losses)............ 103 107 387 131 728
------- ------- ------- ------- -------
Historical cost profit before
interest and tax.......................... 3,888 2,101 8,065 4,573 18,627
------- ------- ------- ------- -------
Total assets (f)............................ 35,713 14,584 63,145 31,420 144,862
Operating capital employed (g).............. 20,093 7,087 45,661 28,777 101,618
Depreciation and amounts provided (h)....... 1,945 373 4,165 1,307 7,790
Capital expenditure and acquisitions (i).... 7,438 2,041 34,037 4,097 47,613
F - 92
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 49 -- Business and geographical analysis (concluded)
---------------
(a) Other businesses and corporate comprises Finance, the Group's coal asset
and aluminium asset, its investment in PetroChina and Sinopec, interest
income and costs relating to corporate activities worldwide.
(b) Sales and transfers between businesses are made at prices that approximate
market prices taking into account the volumes involved.
(c) Equity accounted income (loss) represents the Group's share of income
(loss) before exceptional items, inventory gains (losses) interest expense
and taxes of joint ventures and associated undertakings.
(d) Replacement cost operating profit is before inventory holding gains and
losses and interest expense, which is attributable to the corporate
function. Transfers between Group companies are made at prices that
approximate market prices taking into account the volumes involved.
(e) Exceptional items comprise profit or loss on the sale of fixed assets and
sale of businesses or termination of operations of $1,168 million in 2002
(2001 $535 million profit and 2000 $220 million profit).
(f) Total assets comprise fixed and current assets and include investments in
joint ventures and associated undertakings analyzed between activities as
follows:
Gas Other
Exploration Power Refining businesses
and and and and
Production Renewables Marketing Chemicals corporate(a) Total
--------- ---------- --------- --------- --------- ---------
($ million)
2002................ 5,687 210 1,452 1,252 56 8,657
--------- --------- --------- --------- --------- ---------
2001................ 5,326 857 1,675 1,416 20 9,294
--------- --------- --------- --------- --------- ---------
2000................ 5,093 744 1,220 1,155 47 8,259
--------- --------- --------- --------- --------- ---------
(g) Operating capital employed comprises net assets before deducting finance
debt and liabilities for current and deferred taxation.
(h) Depreciation consists of charges for depreciation, depletion and
amortization of property, plant and equipment, exploration expense and
amounts provided against fixed asset investments.
(i) Capital expenditure and acquisitions includes $170 million in 2000 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.
F - 93
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles
The consolidated financial statements of the BP Group are prepared in
accordance with UK GAAP which differs in certain respects from US GAAP. The
principal differences between US GAAP and UK GAAP for BP Group reporting relate
to the following:
(a) Group consolidation
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 permits these activities to be accounted
for by proportional consolidation, which is equivalent to UK GAAP.
Joint ventures and associated undertakings 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
joint ventures and associated undertakings. In addition the Group's share
of turnover of joint ventures should be disclosed. For US GAAP the after
tax profits or losses (i.e. operating results after exceptional items,
inventory holding gains or losses, interest expense and taxation) are
included in the income statement as a single line item.
UK GAAP requires the Group's share of the gross assets and gross
liabilities of joint ventures to be shown on the face of the balance sheet
whereas under US GAAP the net investment is included as a single line item.
F - 94
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
The following summarizes the reclassifications for joint ventures and
associated undertakings necessary to accord with US GAAP.
Year ended December 31, 2002
---------------------------------------------
As US GAAP
Increase (decrease) in caption heading reported Reclassification presentation
---------- ---------------- ------------
($ million)
Consolidated statement of income
Other income................................................. 641 563 1,204
Share of profits of JVs and associated undertakings.......... 962 (962) --
Exceptional items before taxation............................ 1,168 (2) 1,166
Inventory holding gains (losses)............................. 1,129 (2) 1,127
Interest expense............................................. 1,279 (141) 1,138
Taxation..................................................... 4,342 (262) 4,080
Profit for the year.......................................... 6,845 -- 6,845
Year ended December 31, 2001
---------------------------------------------
As US GAAP
Increase (decrease) in caption heading reported Reclassification presentation
---------- ---------------- ------------
($ million)
Consolidated statement of income
Other income................................................. 694 692 1,386
Share of profits of JVs and associated undertakings.......... 1,203 (1,203) --
Exceptional items before taxation............................ 535 2 537
Inventory holding gains (losses)............................. (1,900) 7 (1,893)
Interest expense............................................. 1,670 (205) 1,465
Taxation..................................................... 6,375 (297) 6,078
Profit for the year.......................................... 6,556 -- 6,556
Year ended December 31, 2000
---------------------------------------------
As US GAAP
Increase (decrease) in caption heading reported Reclassification presentation
---------- ---------------- ------------
($ million)
Consolidated statement of income
Other income................................................. 805 1,416 2,221
Share of profits of JVs and associated undertakings.......... 1,600 (1,600) --
Exceptional items before taxation............................ 220 (24) 196
Inventory holding gains (losses)............................. 728 (229) 499
Interest expense............................................. 1,770 (218) 1,552
Taxation..................................................... 6,648 (219) 6,429
Profit for the year.......................................... 10,120 -- 10,120
F - 95
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(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.
(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 fixed assets and businesses or sale or termination of
operations and fundamental restructuring charges. Under US GAAP these items
are classified as operating income or expenses.
(d) Deferred taxation/Business combinations
US GAAP requires the recognition of a deferred tax asset or liability for
the tax effects of differences between the assigned values and the tax
bases of assets acquired and liabilities assumed in a purchase business
combination, whereas under UK GAAP no such deferred tax asset or liability
is recognized. Under US GAAP the deferred tax asset or liability is
amortized over the same period as the assets and liabilities to which it
relates.
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($million)
Replacement cost of sales................................. 852 1,091 706
Taxation ................................................. (537) (276) (777)
Profit for the year....................................... (315) (815) 71
======== ======== =========
At December 31,
------------------
2002 2001
------ ------
($ million)
Tangible assets........................................... 7,408 7,032
Deferred taxation......................................... 7,486 6,789
BP shareholders' interest................................. (78) 243
====== ======
F - 96
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(d) Deferred taxation/Business combinations (concluded)
The major components of deferred tax liabilities and assets on a US GAAP
basis were as follows:
December 31,
------------------
2002 2001
------ ------
($ million)
Depreciation...................................................... (22,472) (19,709)
Other taxable temporary differences............................... (2,731) (1,110)
------ ------
Total deferred tax liabilities.................................... (25,203) (20,819)
------ ------
Petroleum revenue tax............................................. 567 383
Decommissioning and other provisions.............................. 5,030 2,446
Tax credit and loss carry forward................................. 1,823 1,487
Other deductible temporary differences............................ 423 668
------ ------
Gross deferred tax assets......................................... 7,843 4,984
Valuation allowance............................................... (1,726) (1,474)
------ ------
Net deferred tax assets........................................... 6,117 3,510
------ ------
Net deferred tax liability*....................................... (19,086) (17,309)
====== ======
----------
* Primarily noncurrent.
(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. Unwinding of the discount and the
effect of a change in the discount rate is included in interest expense in
the period. When a decommissioning provision is set up, a tangible fixed
asset of the same amount is also recognized and is subsequently depreciated
as part of the capital costs of the facilities. 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; there is no corresponding tangible fixed asset.
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Replacement cost of sales......................................... 334 523 340
Interest expense.................................................. (212) (238) (189)
Taxation.......................................................... (130) (103) (83)
Profit for the year............................................... 8 (182) (68)
======== ======== =========
F - 97
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(e) Provisions (concluded)
At December 31,
------------------
2002 2001
------ ------
($ million)
Tangible assets................................................... (1,297) (785)
Provisions........................................................ 412 780
Deferred taxation................................................. (621) (511)
BP shareholders' interest......................................... (1,088) (1,054)
====== ======
(f) 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.
UK GAAP permits assets and liabilities acquired on a business combination
to be revised in the year following that in which the acquisition was made.
US GAAP does not permit such adjustments.
In 2001 a revision of $911 million to the previously reported fair values
for tangible fixed assets relating to the 2000 acquisition of ARCO under UK
GAAP has been reflected as a charge for impairment under US GAAP.
The adjustments to profit for the year to accord with US GAAP are shown
below. There is no impact on BP shareholders' interest. The consequential
Balance Sheet adjustments are reflected in (d) Deferred taxation/Business
combinations and (h) Goodwill and intangible assets.
Increase (decrease) in caption heading Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Replacement cost of sales......................................... -- 1,150 --
Taxation.......................................................... -- (239) --
Profit for the year............................................... -- (911) --
======== ======== ========
F - 98
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(g) Sale and leaseback
The sale and leaseback of an office building in Chicago, Illinois in 1998
was treated as a sale for UK GAAP whereas for US GAAP it was 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. A further provision has been
recognized in 2002 under UK GAAP, which has also been reversed for US GAAP.
Under UK GAAP the profit arising on the sale and operating leaseback of
certain railcars in 1999 was taken to income in the period in which the
transaction occurs. Under US GAAP this profit was not recognized
immediately but amortized over the term of the operating lease.
The adjustments to profit for the year and BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Replacement cost of sales............................... (40) 51 49
Taxation................................................ 16 (15) (15)
Profit for the year..................................... 24 (36) (34)
======== ======== =========
At December 31,
------------------
2002 2001
------ ------
($ million)
Tangible assets................................................... 161 171
Other accounts payable and accrued liabilities.................... 27 30
Provisions........................................................ (117) (65)
Finance debt...................................................... 413 413
Deferred taxation................................................. (56) (73)
BP shareholders' interest......................................... (106) (134)
====== ======
F - 99
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(h) Goodwill and intangible assets
Various differences in the basis for determining goodwill between UK and US
GAAP result in goodwill for US GAAP reporting differing from the amount
recognised under UK GAAP.
On January 1, 2002 the Group adopted Statement of Financial Accounting
Standards No. 142 'Goodwill and Other Intangible Assets' (SFAS 142) for US
GAAP reporting. This standard eliminates the requirement to amortize
goodwill and indefinite lived intangible assets. Rather, such assets are
subject to periodic impairment testing. Intangible assets that are not
deemed to have an indefinite life continue to be amortized over their
estimated useful lives. Amortization of goodwill charged to income under UK
GAAP has been reversed for US GAAP.
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Replacement cost of sales................................. (1,302) (60) (43)
Taxation.................................................. -- -- --
Profit for the year....................................... 1,302 60 43
======== ======== =========
At December 31,
------------------
2002 2001
------ ------
($ million)
Intangible assets......................................... (84) (1,414)
Deferred taxation......................................... -- --
BP shareholders' interest................................. (84) (1,414)
====== ======
F - 100
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(h) Goodwill and intangible assets (continued)
Profit for the year, as adjusted to accord with US GAAP, to exclude
amortization of goodwill no longer being amortized pursuant to SFAS 142 is
shown below.
Year ended
December 31,
------------------
2002 2001
------ ------
($ million)
Profit for the year applicable to ordinary shares as
adjusted to accord with US GAAP, as reported............................... 4,162 10,181
Add back goodwill amortization............................................... 1,228 788
------ ------
Profit for the year as adjusted to accord with US GAAP, as adjusted.......... 5,390 10,969
------ ------
Per ordinary share-- cents
Basic-- as reported...................................................... 18.55 47.05
Adjustment............................................................... 5.47 3.64
------ ------
Basic-- as adjusted...................................................... 24.02 50.69
------ ------
Diluted-- as reported.................................................... 18.44 46.74
Adjustment............................................................... 5.44 3.62
------ ------
Diluted-- as adjusted.................................................... 23.88 50.36
------ ------
Per American Depositary Share -- cents
Basic-- as reported...................................................... 111.30 282.30
Adjustment............................................................... 32.82 21.84
------ ------
Basic-- as adjusted...................................................... 144.12 304.14
------ ------
Diluted-- as reported.................................................... 110.64 280.44
Adjustment............................................................... 32.64 21.72
------ ------
Diluted-- as adjusted.................................................... 143.28 302.16
------ ------
F - 101
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(h) Goodwill and intangible assets (concluded)
Changes to exploration expenditure, goodwill and other intangible assets,
as adjusted to accord with US GAAP, during the year ended December 31, 2002
are shown below.
Exploration Other
expenditure Goodwill intangibles Total
----------- -------- ----------- -----
($ million)
Net book amount
At January 1, 2002................................... 5,334 9,453 588 15,375
Amortization expense................................. (385) -- (189) (574)
Acquisitions......................................... -- 545 -- 545
Other movements...................................... (5) 356 89 440
----- ------ ----- ------
At December 31, 2002................................. 4,944 10,354 488 15,786
===== ====== ===== ======
Amortization expense relating to other intangibles is expected to be in the
range $100-$200 million in each of the succeeding five years.
During the second quarter of 2002 the Group completed a goodwill impairment
review using the two-step process prescribed in SFAS 142. The first step
includes a comparison of the fair value of a reporting unit to its carrying
value, including goodwill. Where the carrying value exceeds the fair value,
the goodwill of the reporting unit is potentially impaired and the second
step is then completed in order to measure the impairment loss, if any. No
impairment charge resulted from this review.
(i) Derivative financial instruments and hedging activities
On January 1, 2001 the Group adopted Statement of Financial Accounting
Standards No. 133 'Accounting for Derivative Instruments and Hedging
Activities' (SFAS 133) as amended by Statement Nos. 137 and 138, for US
GAAP reporting.
SFAS 133, as amended, requires that all derivative instruments be recorded
on the balance sheet at their fair value. Changes in the fair value of
derivatives are recorded each period in current earnings or other
comprehensive income, depending on whether a derivative is designated as
part of a hedge transaction and, if it is, the type of hedge transaction.
To the extent certain criteria are met, SFAS 133 permits, but does not
require, hedge accounting.
In the normal course of business the Group is a party to derivative
financial instruments 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. In addition, the Group trades derivatives in
conjunction with these risk management activities.
F - 102
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(i) Derivative financial instruments and hedging activities (concluded)
All oil price derivatives and all derivatives held for trading are carried
on the Group's balance sheet at fair value with changes in that value
recognized in earnings of the period for both UK and US GAAP. Certain
financial derivatives used to manage foreign currency and interest rate
risk that qualify for hedge accounting under UK GAAP are marked-to-market
under SFAS 133. For these derivatives, the cumulative effect of adopting
SFAS 133 resulted in a pre-tax charge to income, as adjusted to accord with
US GAAP, of $27 million ($18 million after tax). Under US GAAP the fair
values of derivative financial instruments are shown as current assets and
liabilities as appropriate.
The Group has a number of long-term natural gas contracts which have been
in place for many years. The pricing structure for those contracts is not
directly related to the market price of natural gas but to the price of
other commodities or indices, such as fuel oil or consumer price indices.
On the basis of SFAS 133 Implementation Issue C11, these contracts have
been marked to market with effect from July 1, 2001.
In October 2002, the FASB Emerging Issues Task Force (EITF) reached a
consensus with regards to EITF Issue No. 02-3, 'Issues Involved in
Accounting for Contracts Under EITF Issue No. 98-10 'Accounting for
Contracts Involved in Energy Trading and Risk Management Activities'' (EITF
02-3). Under this consensus trading inventories should be recorded on the
balance sheet at historical cost. The Group marks trading inventories to
market at the balance sheet date. Thus a UK/US GAAP difference arises which
impacts both profit for the year and BP shareholders' interest due to the
difference in inventory valuations.
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Replacement cost of sales.................................... (842) 481 --
Taxation..................................................... 302 (168) --
Profit for the year before cumulative
effect of accounting change................................ 540 (313) --
Cumulative effect of accounting change,
net of taxation............................................ -- (362) --
Profit for the year.......................................... 540 (675) --
====== ====== ======
At December 31,
------------------
2002 2001
------ ------
($ million)
Inventories.................................................. (209) --
Accounts payable and accrued liabilities..................... (13) 1,038
Deferred taxation............................................ (61) (363)
BP shareholders' interest.................................... (135) (675)
====== ======
F - 103
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(j) Gain arising on asset exchange
For UK GAAP the transaction with Solvay in 2001, which led to the exchange
of businesses for an interest in a joint venture and an associated
undertaking, has been treated as an asset swap which does not give rise to
a gain or loss. Under US GAAP the transaction has been treated as a
disposal and acquisition at fair value which gives rise to a pre-tax gain
on disposal of $242 million ($157 million after tax).
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Profit (loss) on sale of fixed assets and
businesses or termination of operations.................... -- 242 --
Replacement cost of sales.................................... 27 -- --
Taxation..................................................... (9) 85 --
Profit for the year.......................................... (18) 157 --
======== ======== =========
At December 31,
------------------
2002 2001
------ ------
($ million)
Intangible assets............................................ 167 188
Accounts payable and accrued liabilities..................... (52) (54)
Deferred taxation............................................ 77 85
BP shareholders' interest.................................... 142 157
====== ======
(k) 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.
The adjustment to BP shareholders' interest to accord with US GAAP is shown
below.
At December 31,
------------------
Increase (decrease) in caption heading 2002 2001
------ ------
($ million)
Fixed assets - Investments........................................ (159) (266)
BP shareholders' interest......................................... (159) (266)
====== ======
F - 104
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(l) 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.
The adjustment to BP shareholders' interest to accord with US GAAP is shown
below.
At December 31,
------------------
Increase (decrease) in caption heading 2002 2001
------ ------
($ million)
Other accounts payable and accrued liabilities.................... (1,398) (1,288)
BP shareholders' interest......................................... 1,398 1,288
====== ======
(m) Investments
Under UK GAAP certain of the Group's equity investments are reported as
either fixed asset or current asset investments and carried on the balance
sheet at cost subject to review for impairment. For US GAAP these
investments are classified as available-for-sale securities. Consequently
they are reported at fair value, with unrealized holding gains and losses,
net of tax, reported in accumulated other comprehensive income. If a
decline in fair value below cost is 'other than temporary' the unrealized
loss is accounted for as a realized loss and charged against income.
The adjustment to BP shareholders' interest to accord with US GAAP is shown
below.
At December 31,
------------------
Increase (decrease) in caption heading 2002 2001
------ ------
($ million)
Fixed assets - investments........................................ 52 (3)
Deferred taxation................................................. 18 (1)
BP shareholders' interest......................................... 34 (2)
====== ======
F - 105
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
(n) Additional minimum pension liability
Where a pension plan has an unfunded accumulated benefit obligation, US
GAAP requires such amount to be recognized as a liability in the balance
sheet. The adjustment resulting from the recognition of any such minimum
liability, including the elimination of amounts previously recognized as a
prepaid benefit cost, is reported as an intangible asset to the extent of
unrecognized prior service cost with the remaining amount reported in
comprehensive income.
The adjustments to accumulated other comprehensive income (BP shareholders'
interest) to accord with US GAAP are summarized below.
At December 31,
------------------
Increase (decrease) in caption heading 2002 2001
------ ------
($ million)
Intangible assets................................................. 137 112
Other receivables falling due after more
than one year................................................... (1,211) (1,015)
Noncurrent liabilities -- accounts payable and
accrued liabilities............................................. 2,459 548
Deferred taxation................................................. (1,247) (509)
BP shareholders' interest......................................... (2,286) (942)
====== ======
(o) Balance sheet
Under USGAAP Trade and Other receivables due after one year of $6,245
million at December 31, 2002 ($4,681 million at December 31, 2001),
included within current assets, would have been classified as noncurrent
assets. Borrowing under US Industrial Revenue/Municipal Bonds of $1,881
million ($1,768 million at December 31, 2001) included within Current
Liabilities -- falling due within one year would, under US GAAP, have been
classified as noncurrent liabilities. The provision for deferred taxation
is primarily in respect of noncurrent items.
F - 106
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
The following is a summary of the adjustments to profit for the year and to
BP shareholders' interest which would be required if generally accepted
accounting principles in the United States (US GAAP) had been applied instead of
those generally accepted in the United Kingdom (UK GAAP).
These results are stated using the first-in first-out method of inventory
valuation.
Profit for the year
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million except
per share amounts)
Profit as reported in the consolidated statement of income............. 6,845 6,556 10,120
Deferred taxation/business combinations (d)............................ (315) (815) 71
Provisions (e)......................................................... 8 (182) (68)
Impairment (f)......................................................... -- (911) --
Sale and leaseback (g)................................................. 24 (36) (34)
Goodwill and intangible assets (h)..................................... 1,302 60 43
Derivative financial instruments (i)................................... 540 (313) --
Gain arising on asset exchange (j)..................................... (18) 157 --
Other.................................................................. 11 10 51
-------- -------- ---------
Profit for the year before cumulative effect of accounting
change as adjusted to accord with US GAAP............................ 8,397 4,526 10,183
Cumulative effect of accounting change:
Derivative financial instruments (i)................................. -- (362) --
-------- -------- ---------
Profit for the year as adjusted to accord with US GAAP................. 8,397 4,164 10,183
Dividend requirements on preference shares............................. 2 2 2
-------- -------- ---------
Profit for the year applicable to ordinary shares as
adjusted to accord with US GAAP...................................... 8,395 4,162 10,181
======== ======== =========
Profit for the year as adjusted:
Per ordinary share-- cents
Basic-- before cumulative effect of accounting change................ 37.48 20.16 47.05
Cumulative effect of accounting change............................... -- (1.61) --
-------- -------- ---------
37.48 18.55 47.05
-------- -------- ---------
Diluted-- before cumulative effect of accounting change.............. 37.30 20.04 46.74
Cumulative effect of accounting change............................... -- (1.60) --
-------- -------- ---------
37.30 18.44 46.74
-------- -------- ---------
Per American Depositary Share - cents (ii)
Basic-- before cumulative effect of accounting change................ 224.88 120.96 282.30
Cumulative effect of accounting change............................... -- (9.66) --
-------- -------- ---------
224.88 111.30 282.30
-------- -------- ---------
Diluted-- before cumulative effect of accounting change.............. 223.80 120.24 280.44
Cumulative effect of accounting change............................... -- (9.60) --
-------- -------- ---------
223.80 110.64 280.44
-------- -------- ---------
F - 107
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
BP shareholders' interest
December 31,
------------------
2002 2001
------ ------
($ million)
BP shareholders' interest as reported in the consolidated balance sheet......... 69,409 65,161
Deferred taxation/business combinations (d)..................................... (78) 243
Provisions (e).................................................................. (1,088) (1,054)
Sale and leaseback (g).......................................................... (106) (134)
Goodwill and intangible assets (h).............................................. (84) (1,414)
Derivative financial instruments (i)............................................ (135) (675)
Gain arising on asset exchange (j).............................................. 142 157
Ordinary shares held for future awards to employees (k)......................... (159) (266)
Dividends (l)................................................................... 1,398 1,288
Investments (m)................................................................. 34 (2)
Additional minimum pension liability (n)........................................ (2,286) (942)
Other........................................................................... (48) (40)
------ ------
BP shareholders' interest as adjusted to accord with US GAAP.................... 66,999 62,322
====== ======
(i) The profit reported under UK GAAP for years ended December 31, 2001 and
2000 has been restated to reflect the adoption of FRS19. Consequently
certain of the adjustments in the UK/US GAAP reconciliation have also been
restated. Profit and BP Shareholders' interest, as adjusted to accord with
US GAAP, are unaffected by the adoption of FRS 19.
(ii) One American Depositary Share is equivalent to six ordinary shares.
Comprehensive income
The components of comprehensive income, net of related tax are as follows:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Profit for the period as adjusted to accord with US GAAP............... 8,397 4,164 10,183
Currency translation differences....................................... 3,333 (828) (2,340)
Net unrealized gain (loss) on investments.............................. 36 110 (112)
Additional minimum pension liability................................... (1,344) (797) (1)
-------- -------- ---------
Comprehensive income................................................... 10,422 2,649 7,730
======== ======== =========
Accumulated other comprehensive income at December 31, 2002 comprised
currency translation losses of $1,377 million (losses $4,710 million at December
31, 2001), pension liability adjustments of $2,286 million ($942 million at
December 31, 2001) and net unrealized gains on investments of $34 million gain
($2 million loss at December 31, 2001).
F - 108
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
Consolidated statement of cash flows
The Group's financial statements include a consolidated statement of cash
flows in accordance with the revised UK Financial Reporting Standard No. 1
(FRS1). The statement prepared under FRS1 presents substantially the same
information as that required under FASB Statement of Financial Accounting
Standards No. 95 'Statement of Cash Flows' (SFAS 95).
Under FRS1 cash flows are presented for (i) operating activities; (ii)
dividends from joint ventures; (iii) dividends from associated undertakings;
(iv) servicing of finance and returns on investments; (v) taxation; (vi) capital
expenditure and financial investment; (vii) acquisitions and disposals; (viii)
dividends; (ix) financing; and (x) management of liquid resources. SFAS 95 only
requires presentation of cash flows from operating, investing and financing
activities.
Cash flows under FRS1 in respect of dividends from joint ventures and
associated undertakings, taxation and servicing of finance and returns on
investments are included within operating activities under SFAS 95. Interest
paid includes payments in respect of capitalized interest, which under SFAS 95
are included in capital expenditure under investing activities. Cash flows under
FRS1 in respect of capital expenditure and acquisitions and disposals are
included in investing activities under SFAS 95. Dividends paid are included
within financing activities. All short-term investments are regarded as liquid
resources for FRS1. Under SFAS 95 short-term investments with original
maturities of three months or less are classified as cash equivalents and
aggregated with cash in the cash flow statement. Cash flows in respect of
short-term investments with original maturities exceeding three months are
included in operating activities.
F - 109
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
The statement of consolidated cash flows presented in accordance with SFAS
95 is as follows:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Operating activities
Profit after taxation.................................................. 6,922 6,617 10,209
Adjustments to reconcile profit after tax to net cash provided by
operating activities
Depreciation and amounts provided.................................... 10,401 8,858 7,526
Exploration expenditure written off.................................. 385 238 264
Share of profits of joint ventures and associated
undertakings less dividends received............................... 3 (60) (377)
(Profit) loss on sale of businesses and fixed assets................. (1,166) (537) (196)
Working capital movement (a)......................................... (1,416) 1,319 (2,848)
Deferred taxation.................................................... 1,194 1,244 1,564
Other................................................................ (280) (111) (1,538)
-------- -------- ---------
Net cash provided by operating activities.............................. 16,043 17,568 14,604
-------- -------- ---------
Investing activities
Capital expenditures................................................... (12,216) (12,295) (10,220)
Acquisitions, net of cash acquired..................................... (4,324) (1,210) (6,265)
Investment in associated undertakings.................................. (971) (586) (985)
Net investment in joint ventures....................................... (354) (497) (218)
Proceeds from disposal of assets....................................... 6,782 2,903 11,362
-------- -------- ---------
Net cash used in investing activities.................................. (11,083) (11,685) (6,326)
-------- -------- ---------
Financing activities
Proceeds from shares issued (repurchased).............................. (555) (1,100) (2,039)
Proceeds from long-term financing...................................... 3,707 1,296 1,680
Repayments of long-term financing...................................... (2,369) (2,602) (2,353)
Net (decrease) increase in short-term debt............................. (602) 1,434 (701)
Dividends paid -- BP shareholders...................................... (5,264) (4,827) (4,415)
-- Minority shareholders................................ (40) (54) (24)
-------- -------- ---------
Net cash used in financing activities.................................. (5,123) (5,853) (7,852)
-------- -------- ---------
Currency translation differences relating to cash
and cash equivalents................................................. 90 (53) (50)
-------- -------- ---------
Increase (decrease) in cash and cash equivalents....................... (73) (23) 376
Cash and cash equivalents at beginning of year......................... 1,808 1,831 1,455
-------- -------- ---------
Cash and cash equivalents at end of year............................... 1,735 1,808 1,831
======== ======== =========
----------
(a) Working capital:
Inventories (increase) decrease................................... (1,521) 1,490 (1,449)
Receivables (increase) decrease................................... (2,750) 1,905 (5,501)
Current liabilities -- excluding finance debt increase (decrease). 2,855 (2,076) 4,102
-------- -------- ---------
(1,416) 1,319 (2,848)
======== ======== =========
F - 110
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
Impact of new US accounting standards
New US accounting standards adopted: The Group has adopted Statement of
Financial Accounting Standards No. 141 'Business Combinations' (SFAS 141) for US
GAAP reporting with effect from January 1, 2002. Under SFAS 141, the pooling of
interest method of accounting is no longer permitted. Also on January 1, 2002
the Group adopted Statement of Financial Accounting Standards No. 144
'Accounting for the Impairment or Disposal of Long-Lived Assets' (SFAS 144).
SFAS 144 retains the requirement to recognize an impairment loss only where the
carrying value of a long-lived asset is not recoverable from its undiscounted
cash flows and to measure such loss as the difference between the carrying
amount and fair value of the asset. SFAS 144, among other things, changes the
criteria that have to be met in order to classify an asset as held-for-sale and
requires that operating losses from discontinued operations be recognized in the
period that the losses are incurred rather than as of the measurement date.
The adoption of SFAS 141 and SFAS 144 had no impact on profit, as adjusted
to accord with US GAAP, for the year ended December 31, 2002 or on BP
shareholders' interest, as adjusted to accord with US GAAP, at December 31,
2002.
Asset retirement obligations: In June 2001, the Financial Accounting
Standards Board (FASB) issued Statement of Financial Accounting Standards No.
143 'Accounting for Asset Retirement Obligations' (SFAS 143). SFAS 143 requires
companies to record liabilities equal to the fair value of their asset
retirement obligations when they are incurred (typically when the asset is
installed at the production location). When the liability is initially recorded,
companies capitalize an equivalent amount as part of the cost of the asset. Over
time the liability is accreted for the change in its present value each period,
and the initial capitalized cost is depreciated over the useful life of the
related asset. SFAS 143 is effective for accounting periods beginning after June
15, 2002.
The cumulative effect of adopting SFAS 143 at January 1, 2003 will result
in an after tax credit to income, as adjusted to accord with US GAAP, of
approximately $1,700 million. The effect of adoption also included an increase
in total assets, as adjusted to accord with US GAAP, of approximately $660
million and a reduction in total liabilities, as adjusted to accord with US
GAAP, of approximately $1,040 million. It is expected that there will be an
additional charge to profit, adjusted to accord with US GAAP, in the range of
$200 to $250 million in future periods.
Costs associated with exit or disposal activities: In June 2002, the FASB
issued Statement of Financial Accounting Standards No. 146 'Accounting for Costs
Associated with Exit or Disposal Activities' (SFAS 146). SFAS 146 requires that
a liability for costs associated with an exit or disposal activity be recognized
only when the liability is incurred, rather than at the date of an entity's
commitment to an exit plan. SFAS 146 requires that the liability be initially
measured at fair value. SFAS 146 is effective for exit or disposal activities
that are initiated after December 31, 2002.
Contracts involved in energy trading activities: In October 2002, the FASB
Emerging Issues Task Force (EITF) reached a consensus which rescinded EITF Issue
No. 98-10, 'Accounting for Contracts Involved in Energy Trading and Risk
Management Activities' (EITF 98-10). As a result of this consensus, all
energy-related, non-derivative contracts (such as transportation, storage,
tolling, and requirements contracts that do not meet the definition of a
derivative) and trading inventories that are accounted for at fair value
pursuant to EITF 98-10 will no longer be accounted for at fair value upon
application of the consensus. Rather, such contracts will be accounted for as
executory contracts on an accruals basis.
F - 111
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (continued)
The consensus is applicable for all contracts executed after October 25,
2002. Application of the consensus to contracts existing prior to October 26,
2002 is required to be accounted for as a cumulative effect of a change in
accounting principle effective for periods beginning after December 15, 2002.
For BP's reporting under UK GAAP, energy-related non-derivative contracts
associated with trading activities are marked to market with gains and losses
recognized in the income statement.
The cumulative effect of adopting the consensus at January 1, 2003 will
result in an after tax credit to income, as adjusted to accord with US GAAP, of
approximately $50 million.
Stock-based compensation: In December 2002, the FASB issued Statement of
Financial Accounting Standards No. 148 'Accounting for Stock-Based Compensation
- Transition and Disclosure' (SFAS 148). SFAS 148 amends SFAS 123 to permit
alternative methods of transition for adopting a fair value based method of
accounting for stock-based employee compensation. Under UK GAAP, the Group uses
the intrinsic value method to account for stock-based employee compensation.
Guarantees: In November 2002, the FASB issued FASB Interpretation No. 45
'Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others' (Interpretation 45).
Interpretation 45 elaborates on existing disclosure requirements for guarantees
and clarifies that a guarantor is required to recognize, at the inception of a
guarantee, a liability for the fair value of the obligation undertaken in
issuing the guarantee. The initial recognition and measurement provisions of
Interpretation 45 apply on a prospective basis to guarantees issued or modified
after December 31, 2002.
Consolidation: In January 2003, the FASB issued FASB Interpretation No. 46
'Consolidation of Variable Interest Entities' (Interpretation 46).
Interpretation 46 clarifies the application of existing consolidation
requirements to entities where a controlling financial interest is achieved
through arrangements that do not involve voting interests. Under Interpretation
46, a variable interest entity is consolidated if a company is subject to a
majority of the risk of loss from the variable interest entity's activities or
entitled to receive a majority of the entity's residual returns. Interpretation
46 applies to variable interest entities created or acquired after January 31,
2003. For variable interest entities existing at January 31, 2003,
Interpretation 46 is effective for accounting periods beginning after June 15,
2003.
The Company is currently carrying out the analysis necessary to adopt
Interpretation 46 in the third quarter of 2003 for existing entities. The
Company does not expect that the adoption of Interpretation 46 will have a
significant effect on profit, as adjusted to accord with US GAAP, or BP
shareholders' interest, as adjusted to accord with US GAAP.
F - 112
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 50 -- US generally accepted accounting principles (concluded)
Impact of new UK Accounting Standards
Retirement benefits: In December 2000, the UK Accounting Standards Board
issued Financial Reporting Standard No. 17 'Retirement Benefits' (FRS 17). This
standard was to be fully effective for accounting periods ending on or after
June 22, 2003 with certain of the disclosure requirements effective for periods
prior to 2003. However, in November 2002, the UK Accounting Standards Board
issued an amendment to FRS 17, which defers full adoption until January 1, 2005
although the disclosure requirements apply to periods prior to 2005. FRS 17
requires that financial statements reflect at fair value the assets and
liabilities arising from an employer's retirement benefit obligations and any
related funding. The operating costs of providing retirement benefits are
recognized in the period in which they are earned together with any related
finance costs and changes in the value of related assets and liabilities.
The pro forma impact of adopting this standard on pensions and
postretirement benefits is shown in Notes 40 and 41 of Notes to Financial
Statements.
Impact of International Accounting Standards
In June 2002, the European Union Council of Ministers adopted a Regulation
which will require the Group to prepare its primary consolidated financial
statements in accordance with International Accounting Standards (IAS) beginning
January 1, 2005, with restatement of prior periods presented. IAS differ in
several respects from UK and US GAAP. In addition, significant revisions to IAS
are currently being contemplated and other revisions may be adopted prior to
January 1, 2005. The Group has not determined the effects of adopting IAS.
Note 51 -- Condensed consolidating information on certain US Subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of
its 100% owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe Bay
Royalty Trust. The following financial information for BP p.l.c., and BP
Exploration (Alaska) Inc. and all other subsidiaries on a condensed
consolidating basis is intended to provide investors with meaningful and
comparable financial information about BP p.l.c. and its subsidiary issuers of
debt securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu
of the separate financial statements of each subsidiary issuer of public debt
securities. Investments include the investments in subsidiaries recorded under
the equity method for the purposes of the condensed consolidating financial
information. Equity income of subsidiaries is the Group's share of replacement
cost operating profit related to such investments. The eliminations and
reclassifications column includes the necessary amounts to eliminate the
intercompany balances and transactions between BP p.l.c., BP Exploration
(Alaska) Inc. and other subsidiaries.
F - 113
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Income statement
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2002
Turnover......................................... 2,356 -- 180,122 (2,292) 180,186
Less: Joint ventures............................. -- -- 1,465 -- 1,465
------- ------- ------- ------- -------
Group turnover................................... 2,356 -- 178,657 (2,292) 178,721
Replacement cost of sales........................ 1,459 -- 156,516 (2,447) 155,528
Production taxes................................. 199 -- 1,075 -- 1,274
------- ------- ------- ------- -------
Gross profit..................................... 698 -- 21,066 155 21,919
Distribution and
administration expenses........................ 12 997 11,623 -- 12,632
Exploration expense.............................. 18 -- 610 16 644
------- ------- ------- ------- -------
668 (997) 8,833 139 8,643
Other income..................................... 31 752 446 (588) 641
------- ------- ------- ------- -------
Group replacement cost
operating profit............................... 699 (245) 9,279 (449) 9,284
Share of profits of joint ventures............... -- -- 346 -- 346
Share of profits of associated undertakings...... -- -- 616 -- 616
Equity-accounted income of subsidiaries.......... 283 10,847 -- (11,130) --
------- ------- ------- ------- -------
Total replacement cost
operating profit............................... 982 10,602 10,241 (11,579) 10,246
Profit (loss) on sale of businesses
or termination of operations................... -- 2,686 2,606 (3,498) 1,794
Profit (loss) on sale of fixed assets............ (4) (601) (622) 601 (626)
------- ------- ------- ------- -------
Replacement cost profit
before interest and tax........................ 978 12,687 12,225 (14,476) 11,414
Inventory holding gains (losses)................. 9 1,129 1,129 (1,138) 1,129
------- ------- ------- ------- -------
Historical cost profit
before interest and tax........................ 987 13,816 13,354 (15,614) 12,543
Interest expense................................. 93 1,712 1,602 (2,128) 1,279
------- ------- ------- ------- -------
Profit before taxation........................... 894 12,104 11,752 (13,486) 11,264
Taxation......................................... 344 4,342 4,065 (4,409) 4,342
------- ------- ------- ------- -------
Profit after taxation............................ 550 7,762 7,687 (9,077) 6,922
Minority shareholders' interest.................. -- -- 77 -- 77
------- ------- ------- ------- -------
Profit for the year.............................. 550 7,762 7,610 (9,077) 6,845
======= ======= ======= ======= =======
F - 114
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Income statement (continued)
The following is a summary of the adjustments to the profit for the period
which would be required if generally accepted accounting principles in the
United States (US GAAP) had been applied instead of those generally accepted in
the United Kingdom.
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2002
Profit as reported............................... 550 7,762 7,610 (9,077) 6,845
Adjustments:
Deferred taxation/business
combinations................................. (129) (315) (232) 361 (315)
Provisions..................................... (1) 8 9 (8) 8
Sale and leaseback............................. -- 24 24 (24) 24
Goodwill....................................... -- 1,302 1,302 (1,302) 1,302
Derivative financial instruments............... (50) 540 540 (490) 540
Gain arising on asset exchange................. -- (18) (18) 18 (18)
Other.......................................... -- 11 11 (11) 11
------- ------- ------- ------- -------
Profit for the year as adjusted to
accord with US GAAP............................ 370 9,314 9,246 (10,533) 8,397
======= ======= ======= ======= =======
F - 115
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Income statement (continued)
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2001
Turnover......................................... 1,919 -- 175,389 (1,919) 175,389
Less: Joint ventures............................. -- -- 1,171 -- 1,171
------- ------- ------- ------- -------
Group turnover................................... 1,919 -- 174,218 (1,919) 174,218
Replacement cost of sales........................ 971 -- 148,077 (2,047) 147,001
Production taxes................................. 192 -- 1,497 -- 1,689
------- ------- ------- ------- -------
Gross profit..................................... 756 -- 24,644 128 25,528
Distribution and
administration expenses........................ 5 846 10,067 -- 10,918
Exploration expense.............................. 55 -- 425 -- 480
------- ------- ------- ------- -------
696 (846) 14,152 128 14,130
Other income..................................... 1 1,365 668 (1,340) 694
------- ------- ------- ------- -------
Group replacement cost
operating profit............................... 697 519 14,820 (1,212) 14,824
Share of profits of joint ventures............... -- -- 443 -- 443
Share of profits of associated undertakings...... -- -- 760 -- 760
Equity-accounted income of subsidiaries.......... 552 16,665 -- (17,217) --
------- ------- ------- ------- -------
Total replacement cost
operating profit............................... 1,249 17,184 16,023 (18,429) 16,027
Profit (loss) on sale of businesses
or termination of operations................... -- (68) -- -- (68)
Profit (loss) on sale of fixed assets............ 1 601 758 (757) 603
------- ------- ------- ------- -------
Replacement cost profit
before interest and tax........................ 1,250 17,717 16,781 (19,186) 16,562
Inventory holding gains (losses)................. (11) (1,900) (1,900) 1,911 (1,900)
------- ------- ------- ------- -------
Historical cost profit
before interest and tax........................ 1,239 15,817 14,881 (17,275) 14,662
Interest expense................................. 101 2,886 2,901 (4,218) 1,670
------- ------- ------- ------- -------
Profit before taxation........................... 1,138 12,931 11,980 (13,057) 12,992
Taxation......................................... 478 6,375 6,285 (6,763) 6,375
------- ------- ------- ------- -------
Profit after taxation............................ 660 6,556 5,695 (6,294) 6,617
Minority shareholders' interest.................. -- -- 61 -- 61
------- ------- ------- ------- -------
Profit for the year.............................. 660 6,556 5,634 (6,294) 6,556
======= ======= ======= ======= =======
F - 116
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Income statement (continued)
The following is a summary of the adjustments to the profit for the period
which would be required if generally accepted accounting principles in the
United States (US GAAP) had been applied instead of those generally accepted in
the United Kingdom.
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2001
Profit as reported............................... 660 6,556 5,634 (6,294) 6,556
Adjustments:
Deferred taxation/business
combinations................................. (60) (815) (850) 910 (815)
Provisions..................................... (5) (182) (179) 184 (182)
Impairment..................................... -- (911) (911) 911 (911)
Sale and leaseback............................. -- (36) (36) 36 (36)
Goodwill....................................... -- 60 60 (60) 60
Derivative financial instruments............... -- (313) (313) 313 (313)
Gain arising on asset exchange................. -- 157 157 (157) 157
Other.......................................... -- 10 10 (10) 10
------- ------- ------- ------- -------
Profit for the year before cumulative
effect of accounting change as adjusted to
accord with US GAAP............................ 595 4,526 3,572 (4,167) 4,526
Cumulative effect of accounting change:
Derivative financial instruments............... -- (362) (362) 362 (362)
------- ------- ------- ------- -------
Profit for the year as adjusted to
accord with US GAAP............................ 595 4,164 3,210 (3,805) 4,164
======= ======= ======= ======= =======
F - 117
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Income statement (continued)
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2000
Turnover......................................... 2,665 -- 161,826 (2,665) 161,826
Less: Joint ventures............................. -- -- 13,764 -- 13,764
------- ------- ------- ------- -------
Group turnover................................... 2,665 -- 148,062 (2,665) 148,062
Replacement cost of sales........................ 1,126 -- 122,443 (2,772) 120,797
Production taxes................................. 276 -- 1,785 -- 2,061
------- ------- ------- ------- -------
Gross profit..................................... 1,263 -- 23,834 107 25,204
Distribution and
administration expenses....................... 25 603 8,703 -- 9,331
Exploration expense.............................. 26 -- 573 -- 599
------- ------- ------- ------- -------
1,212 (603) 14,558 107 15,274
Other income..................................... (12) 545 811 (539) 805
------- ------- ------- ------- -------
Group replacement cost
operating profit............................... 1,200 (58) 15,369 (432) 16,079
Share of profits of joint ventures............... -- -- 808 -- 808
Share of profits of associated undertakings...... -- -- 792 -- 792
Equity-accounted income of subsidiaries.......... 282 18,081 -- (18,363) --
------- ------- ------- ------- -------
Total replacement cost
operating profit............................... 1,482 18,023 16,969 (18,795) 17,679
Profit (loss) on sale of businesses
or termination of operations................... -- 26,049 (90) (25,827) 132
Profit (loss) on sale of fixed assets............ (1) 88 92 (91) 88
------- ------- ------- ------- -------
Replacement cost profit
before interest and tax........................ 1,481 44,160 16,971 (44,713) 17,899
Inventory holding gains (losses)................. (6) 728 728 (722) 728
------- ------- ------- ------- -------
Historical cost profit
before interest and tax........................ 1,475 44,888 17,699 (45,435) 18,627
Interest expense................................. 22 2,203 2,217 (2,672) 1,770
------- ------- ------- ------- -------
Profit before taxation........................... 1,453 42,685 15,482 (42,763) 16,857
Taxation......................................... 659 6,648 6,220 (6,879) 6,648
------- ------- ------- ------- -------
Profit after taxation............................ 794 36,037 9,262 (35,884) 10,209
Minority shareholders' interest.................. -- -- 89 -- 89
------- ------- ------- ------- -------
Profit for the year.............................. 794 36,037 9,173 (35,884) 10,120
======= ======= ======= ======= =======
F - 118
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Income statement (concluded)
The following is a summary of the adjustments to the profit for the period
which would be required if generally accepted accounting principles in the
United States (US GAAP) had been applied instead of those generally accepted in
the United Kingdom.
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2000
Profit as reported............................... 794 36,037 9,173 (35,884) 10,120
Adjustments:
Deferred taxation/business
combinations................................... 60 71 100 (160) 71
Provisions..................................... (18) (68) (50) 68 (68)
Sale and leaseback............................. -- (34) (34) 34 (34)
Goodwill....................................... -- 43 43 (43) 43
Other.......................................... -- 51 51 (51) 51
------- ------- ------- ------- -------
Profit for the year as adjusted to
accord with US GAAP............................. 836 36,100 9,283 (36,036) 10,183
======= ======= ======= ======= =======
F - 119
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Balance sheet
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
At December 31, 2002
Fixed assets
Intangible assets................................ 427 -- 15,139 -- 15,566
Tangible assets.................................. 6,405 -- 81,277 -- 87,682
Investments
Joint ventures................................. -- -- 4,031 -- 4,031
Associated undertakings........................ -- 3 4,623 -- 4,626
Other.......................................... -- 159 1,995 -- 2,154
Subsidiaries - equity accounted basis.......... 2,561 91,939 -- (94,500) --
------- ------- ------- ------- -------
2,561 92,101 10,649 (94,500) 10,811
------- ------- ------- ------- -------
Total fixed assets............................... 9,393 92,101 107,065 (94,500) 114,059
------- ------- ------- ------- -------
Current assets
Inventories...................................... 102 -- 10,079 -- 10,181
Receivables - amounts falling due:
Within one year................................ 215 1,892 36,700 (11,902) 26,905
After more than one year....................... 17,954 11,689 14,322 (37,720) 6,245
Investments...................................... -- -- 215 -- 215
Cash at bank and in hand......................... (11) 1 1,530 -- 1,520
------- ------- ------- ------- -------
18,260 13,582 62,846 (49,622) 45,066
------- ------- ------- ------- -------
Current liabilities - amounts falling
due within one year
Finance debt..................................... 1,768 -- 10,031 (1,713) 10,086
Other payables................................... 1,129 9,906 35,369 (10,189) 36,215
------- ------- ------- ------- -------
Net current assets (liabilities)................. 15,363 3,676 17,446 (37,720) (1,235)
------- ------- ------- ------- -------
Total assets less current liabilities............ 24,756 95,777 124,511 (132,220) 112,824
Noncurrent liabilities
Finance debt................................... -- -- 11,922 -- 11,922
Other payables................................. 10,586 98 30,491 (37,720) 3,455
Provisions for liabilities and charges
Deferred taxation.............................. 1,686 -- 11,828 -- 13,514
Other.......................................... 489 142 13,255 -- 13,886
------- ------- ------- ------- -------
Net assets....................................... 11,995 95,537 57,015 (94,500) 70,047
Minority shareholders' interest - equity......... -- -- 638 -- 638
------- ------- ------- ------- -------
BP Shareholders' interest........................ 11,995 95,537 56,377 (94,500) 69,409
======= ======= ======= ======= =======
F - 120
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Balance sheet (continued)
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
At December 31, 2002
Capital and reserves
Capital shares................................... 1,903 5,616 -- (1,903) 5,616
Paid in surplus.................................. 3,145 4,243 -- (3,145) 4,243
Merger reserve................................... -- 26,336 697 -- 27,033
Other reserves................................... -- 173 -- -- 173
Retained earnings................................ 6,947 59,169 55,680 (89,452) 32,344
------- ------- ------- ------- -------
11,995 95,537 56,377 (94,500) 69,409
======= ======= ======= ======= =======
The following is a summary of the adjustments to BP shareholders' interest
which would be required if generally accepted accounting principles in the
United States (US GAAP) had been applied instead of those generally accepted in
the United Kingdom.
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
BP Shareholders' interest as reported............ 11,995 95,537 56,377 (94,500) 69,409
Adjustments:
Deferred taxation/
business combinations........................ 74 (78) (152) 78 (78)
Provisions..................................... (190) (1,088) (902) 1,092 (1,088)
Sale and leaseback............................. -- (106) (106) 106 (106)
Goodwill....................................... -- (84) (84) 84 (84)
Derivative financial instruments............... 50 (135) (135) 85 (135)
Gain arising on asset exchange................. -- 142 142 (142) 142
Ordinary shares held for future
awards to employees.......................... -- (159) -- -- (159)
Dividends...................................... -- 1,398 -- -- 1,398
Investments.................................... -- 34 34 (34) 34
Additional minimum pension
liability.................................... -- (2,286) (2,286) 2,286 (2,286)
Other.......................................... -- (48) (48) 48 (48)
------- ------- ------- ------- -------
BP Shareholders' interest as
adjusted to accord with US GAAP.............. 11,929 93,127 52,840 (90,897) 66,999
======= ======= ======= ======= =======
F - 121
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Balance sheet (continued)
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
At December 31, 2001
Fixed assets
Intangible assets................................ 489 -- 16,000 -- 16,489
Tangible assets.................................. 6,418 -- 70,992 -- 77,410
Investments
Joint ventures................................. -- -- 3,861 -- 3,861
Associated undertakings........................ -- 3 5,430 -- 5,433
Other.......................................... -- 266 2,403 -- 2,669
Subsidiaries - equity accounted basis.......... 1,846 76,877 -- (78,723) --
------- ------- ------- ------- -------
1,846 77,146 11,694 (78,723) 11,963
------- ------- ------- ------- -------
Total fixed assets............................... 8,753 77,146 98,686 (78,723) 105,862
------- ------- ------- ------- -------
Current assets
Inventories...................................... 92 -- 7,539 -- 7,631
Receivables - amounts falling due:
Within one year................................ 132 2,700 26,378 (7,222) 21,988
After more than one year....................... 15,201 18,572 15,480 (44,572) 4,681
Investments...................................... -- -- 450 -- 450
Cash at bank and in hand......................... (29) 3 1,384 -- 1,358
------- ------- ------- ------- -------
15,396 21,275 51,231 (51,794) 36,108
------- ------- ------- ------- -------
Current liabilities - amounts falling
due within one year
Finance debt..................................... 406 -- 9,035 (351) 9,090
Other payables................................... 260 7,642 27,797 (7,175) 28,524
------- ------- ------- ------- -------
Net current assets (liabilities)................. 14,730 13,633 14,399 (44,268) (1,506)
------- ------- ------- ------- -------
Total assets less current liabilities............ 23,483 90,779 113,085 (122,991) 104,356
Noncurrent liabilities
Finance debt................................... -- -- 12,327 -- 12,327
Other payables................................. 10,795 191 36,433 (44,333) 3,086
Provisions for liabilities and charges
Deferred taxation.............................. 1,668 -- 11,702 (1,668) 11,702
Other.......................................... 392 216 10,879 (5) 11,482
------- ------- ------- ------- -------
Net assets....................................... 10,628 90,372 41,744 (76,985) 65,759
Minority shareholders' interest - equity......... -- -- 598 -- 598
------- ------- ------- ------- -------
BP Shareholders' interest........................ 10,628 90,372 41,146 (76,985) 65,161
======= ======= ======= ======= =======
F - 122
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Balance sheet (concluded)
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
At December 31, 2001
Capital and reserves
Capital shares................................... 1,050 5,629 -- (1,050) 5,629
Paid in surplus.................................. 3,145 4,014 -- (3,145) 4,014
Merger reserve................................... -- 26,286 697 -- 26,983
Other reserves................................... -- 223 -- -- 223
Retained earnings................................ 6,433 54,220 40,449 (72,790) 28,312
------- ------- ------- ------- -------
10,628 90,372 41,146 (76,985) 65,161
======= ======= ======= ======= =======
The following is a summary of the adjustments to BP shareholders' interest
which would be required if generally accepted accounting principles in the
United States (US GAAP) had been applied instead of those generally accepted in
the United Kingdom.
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
BP shareholders' interest as reported............ 10,628 90,372 41,146 (76,985) 65,161
Adjustments:
Deferred taxation/
business combinations........................ 203 243 86 (289) 243
Provisions..................................... (186) (1,054) (869) 1,055 (1,054)
Sale and leaseback............................. -- (134) (134) 134 (134)
Goodwill....................................... -- (1,414) (1,414) 1,414 (1,414)
Derivative financial instruments............... -- (675) (675) 675 (675)
Gain arising on asset exchange................. -- 157 157 (157) 157
Ordinary shares held for future
awards to employees.......................... -- (266) -- -- (266)
Dividends...................................... -- 1,288 -- -- 1,288
Investments.................................... -- (2) (2) 2 (2)
Additional minimum pension
liability.................................... -- (942) (942) 942 (942)
Other.......................................... -- (40) (40) 40 (40)
------- ------- ------- ------- -------
BP shareholders' interest as
adjusted to accord with US GAAP............... 10,645 87,533 37,313 (73,169) 62,322
======= ======= ======= ======= =======
F - 123
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Cash flow statement
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2002
Net cash inflow (outflow) from
operating activities........................... 1,357 9,108 13,308 (4,431) 19,342
Dividends from joint ventures.................... -- -- 198 -- 198
Dividends from associated
undertakings................................... -- -- 368 -- 368
Dividends from subsidiaries...................... 26 761 -- (787) --
Net cash inflow (outflow) from servicing
of finance and returns on investments.......... (28) 235 (1,118) -- (911)
Tax paid......................................... (75) (2) (3,017) -- (3,094)
Net cash inflow (outflow) for capital
expenditure and financial investment........... (1,097) 151 (8,700) -- (9,646)
Net cash outflow for acquisitions
and disposals.................................. -- (4,431) (1,337) 4,431 (1,337)
Equity dividends paid............................ -- (5,264) (787) 787 (5,264)
------- ------- ------- ------- -------
Net cash inflow (outflow)........................ 183 558 (1,085) -- (344)
======= ======= ======= ======= =======
Financing........................................ 165 560 (906) -- (181)
Management of liquid resources................... -- -- (220) -- (220)
Increase (decrease) in cash...................... 18 (2) 41 -- 57
------- ------- ------- ------- -------
183 558 (1,085) -- (344)
======= ======= ======= ======= =======
The consolidated statement of cash flows presented in accordance with SFAS 95 is
as follows
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Net cash provided by (used in)
operating activities........................... 1,307 10,102 9,753 (5,119) 16,043
Net cash provided by (used in)
investing activities........................... (1,097) (4,279) (10,052) 4,345 (11,083)
Net cash provided by (used in)
financing activities........................... (192) (5,825) 120 774 (5,123)
Currency translation differences relating
to cash and cash equivalents................... -- -- 90 -- 90
------- ------- ------- ------- -------
Increase (decrease) in cash and
cash equivalents............................... 18 (2) (89) -- (73)
Cash and cash equivalents
at beginning of year........................... (29) 3 1,834 -- 1,808
------- ------- ------- ------- -------
Cash and cash equivalents
at end of year................................. (11) 1 1,745 -- 1,735
======= ======= ======= ======= =======
F - 124
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (continued)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(continued)
Cash flow statement (continued)
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2001
Net cash inflow (outflow) from
operating activities........................... 956 6,199 18,249 (2,995) 22,409
Dividends from joint ventures.................... -- -- 104 -- 104
Dividends from associated
undertakings................................... -- -- 528 -- 528
Dividends from subsidiaries...................... -- 1,537 -- (1,537) --
Net cash inflow (outflow) from servicing
of finance and returns on investments.......... -- 1,218 (2,166) -- (948)
Tax paid......................................... (345) (1) (4,314) -- (4,660)
Net cash inflow (outflow) for capital
expenditure and financial investment........... (1,870) (33) (7,946) -- (9,849)
Net cash outflow for acquisitions
and disposals.................................. -- (2,995) (1,755) 2,995 (1,755)
Equity dividends paid............................ -- (4,827) (1,537) 1,537 (4,827)
------- ------- ------- ------- -------
Net cash inflow (outflow)........................ (1,259) 1,098 1,163 -- 1,002
======= ======= ======= ======= =======
Financing........................................ (1,262) 1,097 1,137 -- 972
Management of liquid resources................... -- -- (211) -- (211)
Increase in cash................................. 3 1 237 -- 241
------- ------- ------- ------- -------
(1,259) 1,098 1,163 -- 1,002
======= ======= ======= ======= =======
The consolidated statement of cash flows presented in accordance with SFAS 95 is
as follows
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Net cash provided by (used in)
operating activities........................... 611 8,953 12,401 (4,397) 17,568
Net cash provided by (used in)
investing activities........................... (1,870) (3,028) (9,701) 2,914 (11,685)
Net cash provided by (used in)
financing activities........................... 1,262 (5,924) (2,674) 1,483 (5,853)
Currency translation differences relating
to cash and cash equivalents................... -- -- (53) -- (53)
------- ------- ------- ------- -------
Increase (decrease) in cash and
cash equivalents............................... 3 1 (27) -- (23)
Cash and cash equivalents
at beginning of year........................... (32) 2 1,861 -- 1,831
------- ------- ------- ------- -------
Cash and cash equivalents
at end of year................................. (29) 3 1,834 -- 1,808
======= ======= ======= ======= =======
F - 125
BP p.l.c. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS (Concluded)
Note 51 -- Condensed consolidating information on certain US Subsidiaries
(concluded)
Cash flow statement (concluded)
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Year ended December 31, 2000
Net cash inflow (outflow) from
operating activities........................... 1,683 (12,830) 7,958 23,605 20,416
Dividends from joint ventures.................... -- -- 645 -- 645
Dividends from associated
undertakings................................... -- -- 394 -- 394
Dividends from subsidiaries...................... -- 793 -- (793) --
Net cash inflow (outflow) from servicing
of finance and returns on investments.......... (1) 431 (1,322) -- (892)
Tax paid......................................... (754) 5 (5,449) -- (6,198)
Net cash inflow (outflow) for capital
expenditure and financial investment........... (552) (64) (6,456) -- (7,072)
Net cash outflow for acquisitions
and disposals.................................. 45 18,118 6,307 (23,605) 865
Equity dividends paid............................ -- (4,415) (793) 793 (4,415)
------- ------- ------- ------- -------
Net cash inflow (outflow)........................ 421 2,038 1,284 -- 3,743
======= ======= ======= ======= =======
Financing........................................ 435 2,039 939 -- 3,413
Management of liquid resources................... -- -- 452 -- 452
Decrease in cash................................. (14) (1) (107) -- (122)
------- ------- ------- ------- -------
421 2,038 1,284 -- 3,743
======= ======= ======= ======= =======
The consolidated statement of cash flows presented in accordance with SFAS 95 is
as follows
Issuer Guarantor
----------- ---------
BP Eliminations
Exploration Other and
(Alaska)Inc BP p.l.c. subsidiaries reclassifications BP Group
----------- --------- ------------ ----------------- --------
($ million)
Net cash provided by (used in)
operating activities........................... 928 (11,601) 2,322 22,955 14,604
Net cash provided by (used in)
investing activities........................... (507) 18,054 (149) (23,724) (6,326)
Net cash provided by (used in)
financing activities........................... (435) (6,454) (1,732) 769 (7,852)
Currency translation differences relating
to cash and cash equivalents................... -- -- (50) -- (50)
------- ------- ------- ------- -------
Increase (decrease) in cash and
cash equivalents............................... (14) (1) 391 -- 376
Cash and cash equivalents
at beginning of year........................... (18) 3 1,470 -- 1,455
------- ------- ------- ------- -------
Cash and cash equivalents
at end of year................................. (32) 2 1,861 -- 1,831
======= ======= ======= ======= =======
F - 126
BP 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, 2002, 2001 and 2000.
Movements in estimated net proved reserves of crude oil (a)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(millions of barrels)
2002
Subsidiary undertakings
At January 1
Developed........................................ 1,008 269 2,195 836 4,308
Undeveloped...................................... 317 112 1,394 1,086 2,909
-------- -------- -------- -------- --------
1,325 381 3,589 1,922 7,217
-------- -------- -------- -------- --------
Changes attributable to:
Revisions of previous estimates.................. (58) -- (33) 62 (29)
Purchases of reserves-in-place................... 8 2 -- 217 227
Extensions, discoveries and other additions...... 9 -- 199 649 857
Improved recovery................................ 19 4 60 49 132
Production....................................... (168) (38) (254) (159) (619)
Sales of reserves-in-place....................... (8) -- -- (15) (23)
-------- -------- -------- -------- --------
(198) (32) (28) 803 545
-------- -------- -------- -------- --------
At December 31
Developed........................................ 858 250 2,225 1,002 4,335
Undeveloped...................................... 269 99 1,336 1,723 3,427
-------- -------- -------- -------- --------
1,127 349 3,561 2,725(d) 7,762
======== ======== ======== ======== ========
Equity-accounted entities (BP share)
At January 1
Developed........................................ 5 -- -- 977 982
Undeveloped...................................... -- -- -- 177 177
-------- -------- -------- -------- --------
5 -- -- 1,154 1,159
-------- -------- -------- -------- --------
Changes attributable to:
Revisions of previous estimates.................. -- -- -- 76 76
Purchases of reserves-in-place................... -- -- -- 203 203
Extensions, discoveries and other additions...... -- -- -- 7 7
Improved recovery................................ -- -- -- 55 55
Production....................................... -- -- -- (92) (92)
Sales of reserves-in-place....................... (5) -- -- -- (5)
-------- -------- -------- -------- --------
(5) -- -- 249 244
-------- -------- -------- -------- --------
At December 31
Developed........................................ -- -- -- 1,178 1,178
Undeveloped...................................... -- -- -- 225 225
-------- -------- -------- -------- --------
-- -- -- 1,403 1,403
======== ======== ======== ======== ========
Total Group and BP share of
equity-accounted entities...................... 1,127 349 3,561 4,128 9,165
======== ======== ======== ======== ========
F - 127
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Movements in estimated net proved reserves of crude oil (a) (continued)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(millions of barrels)
2001
Subsidiary undertakings
At January 1
Developed........................................ 1,138 213 2,150 817 4,318
Undeveloped...................................... 254 160 1,043 733 2,190
-------- -------- -------- -------- --------
1,392 373 3,193 1,550 6,508
-------- -------- -------- -------- --------
Changes in year attributable to:
Revisions of previous estimates.................. (16) 16 (39) (58) (97)
Purchases of reserves-in-place................... 9 -- -- 11 20
Extensions, discoveries and other additions...... 94 -- 641 552 1,287
Improved recovery................................ 24 29 48 12 113
Production....................................... (177) (37) (243) (144) (601)
Sales of reserves-in-place....................... (1) -- (11) (1) (13)
-------- -------- -------- -------- --------
(67) 8 396 372 709
-------- -------- -------- -------- --------
At December 31
Developed........................................ 1,008 269 2,195 836 4,308
Undeveloped...................................... 317 112 1,394 1,086 2,909
-------- -------- -------- -------- --------
1,325 381 3,589 (b) 1,922(d) 7,217
======== ======== ======== ======== ========
Equity-accounted entities (BP share)
At January 1
Developed........................................ -- -- -- 986 986
Undeveloped...................................... 5 -- -- 144 149
-------- -------- -------- -------- --------
5 -- -- 1,130 1,135
-------- -------- -------- -------- --------
Changes attributable to:
Revisions of previous estimates.................. -- -- -- 55 55
Extensions, discoveries and other additions...... -- -- -- 24 24
Improved recovery................................ -- -- -- 21 21
Production....................................... -- -- -- (76) (76)
-------- -------- -------- -------- --------
-- -- -- 24 24
-------- -------- -------- -------- --------
At December 31
Developed........................................ 5 -- -- 977 982
Undeveloped...................................... -- -- -- 177 177
-------- -------- -------- -------- --------
5 -- -- 1,154 1,159
======== ======== ======== ======== ========
Total Group and BP share of
equity-accounted entities..................... 1,330 381 3,589 3,076 8,376
======== ======== ======== ======== ========
F - 128
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Movements in estimated net proved reserves of crude oil (a) (continued)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(millions of barrels)
2000
Subsidiary undertakings
At January 1
Developed........................................ 1,158 190 2,930 550 4,828
Undeveloped...................................... 183 95 932 497 1,707
-------- -------- -------- -------- --------
1,341 285 3,862(c) 1,047 6,535
-------- -------- -------- -------- --------
Changes in year attributable to:
Revisions of previous estimates.................. 17 50 40 5 112
Purchases of reserves-in-place................... 146 -- 554 441 1,141
Extensions, discoveries and other additions...... 1 -- 255 201 457
Improved recovery................................ 131 71 105 22 329
Production....................................... (195) (33) (251) (143) (622)
Sales of reserves-in-place....................... (49) -- (1,372)(c) (23) (1,444)
-------- -------- -------- -------- --------
51 88 (669) 503 (27)
-------- -------- -------- -------- --------
At December 31
Developed....................................... 1,138 213 2,150 817 4,318
Undeveloped..................................... 254 160 1,043 733 2,190
-------- -------- -------- -------- --------
1,392 373 3,193 (b) 1,550(d) 6,508
======== ======== ======== ======== ========
Equity-accounted entities (BP share)
At January 1
Developed........................................ -- -- -- 974 974
Undeveloped...................................... 5 -- -- 58 63
-------- -------- -------- -------- --------
5 -- -- 1,032 1,037
-------- -------- -------- -------- --------
Changes attributable to:
Revisions of previous estimates.................. -- -- -- 24 24
Purchases of reserves-in-place................... -- -- -- 73 73
Extensions, discoveries and other additions...... -- -- -- 48 48
Improved recovery................................ -- -- -- 23 23
Production....................................... -- -- -- (68) (68)
Sales of reserves-in-place....................... -- -- -- (2) (2)
-------- -------- -------- -------- --------
-- -- -- 98 98
-------- -------- -------- -------- --------
At December 31
Developed........................................ -- -- -- 986 986
Undeveloped...................................... 5 -- -- 144 149
-------- -------- -------- -------- --------
5 -- -- 1,130 1,135
======== ======== ======== ======== ========
Total Group and BP share of
equity-accounted entities...................... 1,397 373 3,193 2,680 7,643
======== ======== ======== ======== ========
F - 129
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Movements in estimated net proved reserves of crude oil (a) (concluded)
---------------
(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 86
million barrels (43 million barrels at December 31, 2001 and 91 million
barrels at December 31, 2000) upon which a net profits royalty will be
payable over the life of the field under the terms of the BP Prudhoe Bay
Royalty Trust.
(c) The Group's common interest in Altura Energy was sold in 2000. The minority
interest in Altura Energy included 309 million barrels at December 31,
1999.
(d) Minority interest in Trinidad and Tobago LLC included 17 million barrels
(20 million barrels at December 31, 2001 and 23 million barrels at December
31, 2000).
F - 130
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Movements in estimated net proved reserves of natural gas (a)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(billions of cubic feet)
2002
Subsidiary undertakings
At January 1
Developed........................................ 3,212 265 12,232 8,040 23,749
Undeveloped...................................... 1,160 43 2,535 15,472 19,210
-------- -------- -------- -------- --------
4,372 308 14,767 23,512 42,959
-------- -------- -------- -------- --------
Changes in year attributable to:
Revisions of previous estimates.................. (137) 3 (149) 1,175 892
Purchases of reserves-in-place................... 77 3 1 56 137
Extensions, discoveries and other additions...... 126 -- 340 2,702 3,168
Improved recovery................................ 64 -- 738 1,263 2,065
Production....................................... (566) (54) (1,334)(b) (1,147) (3,101)
Sales of reserves-in-place....................... (70) -- (2) (204) (276)
-------- -------- -------- -------- --------
(506) (48) (406) 3,845 2,885
-------- -------- -------- -------- --------
At December 31
Developed........................................ 3,215 216 12,102 8,240 23,773
Undeveloped...................................... 651 44 2,259 19,117 22,071
-------- -------- -------- -------- --------
3,866 260 14,361 27,357(d) 45,844
======== ======== ======== ======== ========
Equity-accounted entities (BP share)
At January 1
Developed........................................ 24 -- -- 1,508 1,532
Undeveloped...................................... -- -- -- 1,684 1,684
-------- -------- -------- -------- --------
24 -- -- 3,192 3,216
-------- -------- -------- -------- --------
Changes attributable to:
Revisions of previous estimates.................. -- -- -- (157) (157)
Purchases of reserves-in-place................... -- -- -- 20 20
Extensions, discoveries and other additions...... -- -- -- 27 27
Improved recovery................................ -- -- -- 1 1
Production....................................... (2) -- -- (138) (140)
Sales of reserves-in-place....................... (22) -- -- -- (22)
-------- -------- -------- -------- --------
(24) -- -- (247) (271)
-------- -------- -------- -------- --------
At December 31
Developed........................................ -- -- -- 1,506 1,506
Undeveloped...................................... -- -- -- 1,439 1,439
-------- -------- -------- -------- --------
-- -- -- 2,945 2,945
======== ======== ======== ======== ========
Total Group and BP share of
equity-accounted entities...................... 3,866 260 14,361 30,302 48,789
======== ======== ======== ======== ========
F - 131
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Movements in estimated net proved reserves of natural gas (a) (continued)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(billions of cubic feet)
2001
Subsidiary undertakings
At January 1
Developed........................................ 3,898 275 12,111 7,985 24,269
Undeveloped...................................... 1,058 71 2,400 13,302 16,831
-------- -------- -------- -------- --------
4,956 346 14,511 21,287 41,100
-------- -------- -------- -------- --------
Changes in year attributable to:
Revisions of previous estimates.................. (25) (10) 16 (707) (726)
Purchases of reserves-in-place................... 14 -- 2 102 118
Extensions, discoveries and other additions...... 70 15 620 3,748 4,453
Improved recovery................................ 136 11 988 132 1,267
Production....................................... (625) (54) (1,358)(b) (1,050) (3,087)
Sales of reserves-in-place....................... (154) -- (12) -- (166)
-------- -------- -------- -------- --------
(584) (38) 256 2,225 1,859
-------- -------- -------- -------- --------
At December 31
Developed........................................ 3,212 265 12,232 8,040 23,749
Undeveloped...................................... 1,160 43 2,535 15,472 19,210
-------- -------- -------- -------- --------
4,372 308 14,767 23,512(d) 42,959
======== ======== ======== ======== ========
Equity-accounted entities (BP share)
At January 1
Developed........................................ -- -- -- 1,268 1,268
Undeveloped...................................... 25 -- -- 1,525 1,550
-------- -------- -------- -------- --------
25 -- -- 2,793 2,818
-------- -------- -------- -------- --------
Changes attributable to:
Revisions of previous estimates.................. (1) -- -- 93 92
Purchases of reserves-in-place................... -- -- -- -- --
Extensions, discoveries and other additions...... -- -- -- 360 360
Improved recovery................................ -- -- -- 71 71
Production....................................... -- -- -- (125) (125)
-------- -------- -------- -------- --------
(1) -- -- 399 398
-------- -------- -------- -------- --------
At December 31
Developed........................................ 24 -- -- 1,508 1,532
Undeveloped...................................... -- -- -- 1,684 1,684
-------- -------- -------- -------- --------
24 -- -- 3,192 3,216
======== ======== ======== ======== ========
Total Group and BP share of
equity-accounted entities...................... 4,396 308 14,767 26,704 46,175
======== ======== ======== ======== ========
F - 132
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Movements in estimated net proved reserves of natural gas (a) (continued)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(billions of cubic feet)
2000
Subsidiary undertakings
At January 1
Developed........................................ 3,354 282 10,439 6,423 20,498
Undeveloped...................................... 919 63 1,552 10,770 13,304
-------- -------- -------- -------- --------
4,273 345 11,991(c) 17,193 33,802
-------- -------- -------- -------- --------
Changes in year attributable to:
Revisions of previous estimates.................. (17) 23 150 331 487
Purchases of reserves-in-place................... 1,099 -- 3,034 2,313 6,446
Extensions, discoveries and other additions...... 253 -- 923 2,343 3,519
Improved recovery................................ 29 28 980 91 1,128
Production....................................... (605) (50) (1,174)(b) (916) (2,745)
Sales of reserves-in-place....................... (76) -- (1,393)(c) (68) (1,537)
-------- -------- -------- -------- --------
683 1 2,520 4,094 7,298
-------- -------- -------- -------- --------
At December 31
Developed........................................ 3,898 275 12,111 7,985 24,269
Undeveloped...................................... 1,058 71 2,400 13,302 16,831
-------- -------- -------- -------- --------
4,956 346 14,511 21,287(d) 41,100
======== ======== ======== ======== ========
Equity-accounted entities (BP share)
At January 1
Developed........................................ -- -- -- 783 783
Undeveloped...................................... 26 -- -- 915 941
-------- -------- -------- -------- --------
26 -- -- 1,698 1,724
-------- -------- -------- -------- --------
Changes attributable to:
Revisions of previous estimates.................. (1) -- -- 167 166
Purchases of reserves-in-place................... -- -- -- 763 763
Extensions, discoveries and other additions...... -- -- -- 176 176
Improved recovery................................ -- -- -- 85 85
Production....................................... -- -- -- (96) (96)
-------- -------- -------- -------- --------
(1) -- -- 1,095 1,094
-------- -------- -------- -------- --------
At December 31
Developed........................................ -- -- -- 1,268 1,268
Undeveloped...................................... 25 -- -- 1,525 1,550
-------- -------- -------- -------- --------
25 -- -- 2,793 2,818
======== ======== ======== ======== ========
Total Group and BP share of
equity-accounted entities...................... 4,981 346 14,511 24,080 43,918
======== ======== ======== ======== ========
F - 133
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Movements in estimated net proved reserves of natural gas (a) (concluded)
----------
(a) Net proved reserves of natural gas exclude production royalties due to
others.
(b) Includes 63 billion cubic feet of natural gas consumed in Alaskan
operations (2001, 61 billion cubic feet and 2000, 55 billion cubic feet).
(c) The Group's common interest in Altura Energy was sold in 2000. The minority
interest in Altura Energy included 155 billion cubic feet of natural gas at
December 31, 1999.
(d) Minority interest in Trinidad and Tobago LLC included 1,185 billion cubic
feet of natural gas (1,258 billion cubic feet at December 31, 2001 and
1,605 billion cubic feet at December 31, 2000).
F - 134
BP 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 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.
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
At December 31, 2002
Future cash inflows (a).......................... 44,300 11,600 146,100 136,900 338,900
Future production and development costs (b)...... 18,400 3,900 39,000 42,700 104,000
Future taxation (c).............................. 9,800 5,300 38,500 34,400 88,000
-------- -------- -------- -------- --------
Future net cash flows............................ 16,100 2,400 68,600 59,800 146,900
10% annual discount (d).......................... 4,800 800 33,100 31,700 70,400
-------- -------- -------- -------- --------
Standardized measure of discounted future
net cash flows................................. 11,300 1,600 35,500 28,100 76,500
======== ======== ======== ======== ========
At December 31, 2001
Future cash inflows (a).......................... 40,600 8,000 83,700 81,400 213,700
Future production and development costs (b)...... 18,800 3,500 33,700 30,600 86,600
Future taxation (c).............................. 5,700 3,000 16,900 18,900 44,500
-------- -------- -------- -------- --------
Future net cash flows............................ 16,100 1,500 33,100 31,900 82,600
10% annual discount (d).......................... 5,300 400 16,600 15,800 38,100
-------- -------- -------- -------- --------
Standardized measure of discounted future
net cash flows................................. 10,800 1,100 16,500 16,100 44,500
======== ======== ======== ======== ========
At December 31, 2000
Future cash inflows (a).......................... 43,800 9,400 187,200 94,100 334,500
Future production and development costs (b)...... 19,000 2,800 38,400 27,300 87,500
Future taxation (c).............................. 7,100 4,700 45,600 27,100 84,500
-------- -------- -------- -------- --------
Future net cash flows............................ 17,700 1,900 103,200 39,700 162,500
10% annual discount (d).......................... 5,000 700 49,200 18,000 72,900
-------- -------- -------- -------- --------
Standardized measure of discounted future
net cash flows................................. 12,700 1,200 54,000 21,700 89,600
======== ======== ======== ======== ========
F - 135
BP 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,
2002, 2001 and 2000:
Years ended December 31,
--------------------------------
2002 2001 2000
-------- -------- ---------
($ million)
Sales and transfers of oil and gas produced, net of
production costs................................................... (22,400) (17,500) (18,400)
Development costs incurred during the year........................... 7,200 6,800 4,500
Extensions, discoveries and improved recovery, less related costs.... 9,700 9,200 13,100
Net changes in prices and production costs (e)....................... 51,600 (74,100) 51,100
Revisions of previous reserve estimates.............................. 2,500 (1,300) 900
Net change in taxation............................................... (16,700) 26,300 (14,800)
Future development costs............................................. (5,100) (3,200) (2,400)
Net change in purchase and sales of reserves-in-place................ 800 (200) 2,400
Addition of 10% annual discount...................................... 4,400 8,900 4,800
------ ------ ------
Total change in the standardized measure during the year............. 32,000 (45,100) 41,200
====== ====== ======
----------
(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 corporate 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.
Equity-accounted entities
In addition, at December 31, 2002 the Group's share of the standardized
measure of discounted future net cash flows of equity-accounted entities
amounted to $4,300 million ($3,400 million at December 31, 2001 and $3,100
million at December 31, 2000).
F - 136
BP 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.
Crude oil and natural gas production
The following table shows crude oil and natural gas production for the
years ended December 31, 2002, 2001 and 2000.
Rest of Rest of
UK Europe USA World Total(d)
-------- -------- -------- -------- --------
(thousand barrels per day)
Production for the year (a)
Crude oil (b)(d)
2002...................................... 462 104 765 687 2,018
2001...................................... 485 100 744 602 1,931
2000...................................... 534 90 729 575 1,928
(million cubic feet per day)
Natural gas (c)(e)
2002...................................... 1,555 147 3,483 3,522 8,707
2001...................................... 1,713 147 3,554 3,218 8,632
2000...................................... 1,652 136 3,054 2,767 7,609
----------
(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 equity-accounted entities of
252,000 b/d in 2002 (2001, 208,000 b/d and 2000, 185,000 b/d).
(e) Includes amounts produced for the Group by equity-accounted entities of 383
mmcf/d in 2002 (2001, 345 mmcf/d and 2000, 263 mmcf/d).
F - 137
BP 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 equity-accounted entities had
interests as of December 31, 2002. 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.
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
Number of productive wells
at December 31, 2002
Oil wells (a) -- gross................... 465 74 6,901 13,453 20,893
-- net..................... 231 24.9 3,999.8 4,405.8 8,661.5
Gas wells (b) -- gross................... 477 39 19,989 2,963 23,468
-- net..................... 219 13.4 12,036.0 1,658.6 13,927.0
----------
(a) Includes approximately 1,905 gross (882.20 net) multiple completion wells
(more than one formation producing into the same well bore).
(b) Includes approximately 2,074 gross (1,238.0 net) multiple completion wells.
If one of the multiple completions in a well is an oil completion, the well
is classified as an oil well.
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(thousands of acres)
Oil and natural gas acreage
at December 31, 2002
Developed
-- gross............................. 753.3 138.6 15,153.3 7,170.8 23,216.0
-- net............................... 353.4 46.3 7,010.5 2,656.8 10,067.0
Undeveloped (a)
-- gross............................. 3,716.6 4,089.5 7,620.0 93,107.1 108,533.2
-- net............................... 1,972.9 1,411.4 4,187.9 38,702.6 46,274.8
----------
(a) Undeveloped acreage includes leases and concessions.
F - 138
BP p.l.c. AND SUBSIDIARIES
SUPPLEMENTARY OIL AND GAS INFORMATION (Concluded)
(Unaudited)
Operational and statistical information (concluded)
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 equity-accounted entities. 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.
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
2002
Exploratory
-- productive............................... 0.8 0.4 2.1 17.3 20.6
-- dry...................................... -- 0.5 1.0 19.5 21.0
Development
-- productive............................... 17.3 1.5 384.2 212.9 615.9
-- dry...................................... 2.8 -- 19.7 28.2 50.7
2001
Exploratory
-- productive............................... 3.2 0.9 5.7 18.7 28.5
-- dry...................................... 1.2 0.7 3.8 2.5 8.2
Development
-- productive............................... 13.5 4.2 705.3 325.2 1,048.2
-- dry...................................... 1.6 -- 25.7 33.5 60.8
2000
Exploratory
-- productive............................... 2.4 0.4 21.5 19.9 44.2
-- dry...................................... -- 1.3 12.4 7.2 20.9
Development
-- productive............................... 12.6 2.5 398.4 425.2 838.7
-- dry...................................... 1.9 -- 45.7 23.4 71.0
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
equity-accounted entities as of December 31, 2002. Suspended development wells
and long-term suspended exploratory wells are also included in the table.
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
At December 31, 2002
Exploratory
-- gross......................................... -- -- 9 17 26
-- net........................................... -- -- 3.1 7.2 10.3
Development
-- gross......................................... 10 2 73 99 184
-- net........................................... 3.5 0.8 46.7 25.6 76.6
F - 139
SCHEDULE II
BP p.l.c. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
Additions
-----------------------
Charged to Charged to
Balance at costs and other Transfers/ Balance
January 1, expenses accounts(a) Deductions December 31,
---------- ---------- ---------- ---------- -----------
($ million)
2002
Fixed assets -- Investments (b).............. 632 13 37 (4) 678
========= ========= ========= ========= =========
Doubtful debts (b)........................... 290 179 49 (73) 445
========= ========= ========= ========= =========
Decommissioning provisions................... 3,304 308 689 (133) 4,168
========= ========= ========= ========= =========
2001
Fixed assets -- Investments (b).............. 505 68 (4) 63 632
========= ========= ========= ========= =========
Doubtful debts (b)........................... 357 131 17 (215) 290
========= ========= ========= ========= =========
Decommissioning provisions................... 3,001 156 353 (206) 3,304
========= ========= ========= ========= =========
2000
Fixed assets -- Investments (b).............. 309 252 (6) (50) 505
========= ========= ========= ========= =========
Doubtful debts (b)........................... 117 99 117 24 357
========= ========= ========= ========= =========
Decommissioning provisions................... 2,785 139 (23) 100(c) 3,001
========= ========= ========= ========= =========
---------------
(a) Principally currency transactions. For decommissioning provisions this also
includes unwinding of discount and the effect of any change in discount
rate.
(b) Deducted in the balance sheet from the assets to which they apply.
(c) Includes $484 million additional provisions in respect of acquisitions.
S - 1
BP p.l.c. AND SUBSIDIARIES
SIGNATURES
The registrant hereby certifies that it meets all of the requirements for
filing on Form 20-F and that it has duly caused and authorized the undersigned
to sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/ D. J. PEARL
.........................
D. J. Pearl
Deputy Company Secretary
Dated: March 24, 2003
BP p.l.c. AND SUBSIDIARIES
CERTIFICATION
I, The Lord Browne of Madingley, certify that:
1. I have reviewed this annual report on Form 20-F of BP p.l.c.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the 'Evaluation Date'); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 24, 2003
/s/ THE LORD BROWNE OF MADINGLEY
--------------------------------
The Lord Browne of Madingley
Group Chief Executive
C - 1
BP p.l.c. AND SUBSIDIARIES
CERTIFICATION
I, Byron Grote, certify that:
1. I have reviewed this annual report on Form 20-F of BP p.l.c.;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this annual report (the 'Evaluation Date'); and
c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 24, 2003
/s/ BYRON E. GROTE
------------------------
Byron E. Grote
Chief Financial Officer
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