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, 2001
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)
Britannic House
1 Finsbury Circus
London EC2M 7BA
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 22,432,076,754
Cumulative First Preference Shares of (pound)1 each 7,232,838
Cumulative Second Preference Shares of (pound)1 each 5,473,414
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
Yes x No
----- -----
Indicate by check mark which financial statement item the Registrant has
elected to follow.
Item 17 Item 18 x
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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............................................ 9
Forward Looking Statements.............................. 10
Statements Regarding Competitive Position............... 10
Item 4 Information on the Company................................... 11
General................................................. 11
Segmental Information................................... 16
Exploration and Production.............................. 18
Gas and Power........................................... 36
Refining and Marketing.................................. 40
Chemicals............................................... 47
Other Businesses and Corporate.......................... 54
Regulation of the Group's Business...................... 56
Environmental Protection................................ 58
Property, Plants and Equipment.......................... 63
Organizational Structure............................... 64
Item 5 Operating and Financial Review and Prospects................. 65
Group Operating Results................................. 65
Liquidity and Capital Resources......................... 77
Critical Accounting Policies
and New Accounting Standards.......................... 80
Item 6 Directors, Senior Management and Employees................... 83
Directors and Senior Management......................... 83
Compensation............................................ 85
Board Practices......................................... 93
Employees............................................... 96
Share Ownership......................................... 97
Item 7 Major Shareholders and Related Party Transactions............ 99
Major Shareholders...................................... 99
Related Party Transactions.............................. 99
Item 8 Financial Information........................................ 99
Consolidated Statements and Other
Financial Information................................. 99
Significant Changes..................................... 100
Item 9 The Offer and Listing........................................ 100
Item 10 Additional Information....................................... 102
Memorandum and Articles of Association.................. 102
Material Contracts...................................... 104
Exchange Controls and Other Limitations Affecting
Security Holders...................................... 104
Taxation................................................ 105
Documents on Display.................................... 106
Item 11 Quantitative and Qualitative Disclosures about Market Risk... 107
Item 12 Description of Securities Other Than Equity Securities....... 113
Part II Item 13 Defaults, Dividend Arrearages and Delinquencies.............. 114
Item 14 Material Modifications to the Rights of Security Holders
and Use of Proceeds..................................... 114
Item 15 Reserved.....................................................
Item 16 Reserved.....................................................
Part III Item 17 Financial Statements......................................... 115
Item 18 Financial Statements......................................... 115
Item 19 Exhibits..................................................... 115
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, that is 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' -- Includes condensate and natural gas liquids.
'Dollar' or '$' -- The US dollar.
'FSA' -- Financial Services Authority.
'Gas' -- Natural Gas.
'LNG' -- Liquefied Natural Gas.
'London Stock Exchange' or 'LSE' -- London Stock Exchange Limited.
'LPG' -- Liquefied Petroleum Gas.
'NGL' -- Natural Gas Liquid.
3
'Noon Buying Rate' -- The noon buying rate in New York City for cable transfers
in pounds as certified for customs purposes by the Federal Reserve Bank of New
York.
'North America' -- the USA and Canada.
'OECD' -- Organization for Economic Cooperation and Development.
'Oil' -- Crude oil, condensate and natural gas liquids.
'OPEC' -- The Organization of Petroleum Exporting Countries.
'Ordinary Shares' -- Ordinary fully paid shares in BP 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.
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.
Years ended December 31,
-----------------------------------------------
2001 2000 1999 1998 1997
----- ----- ----- ----- -----
($ million except per share amounts)
UK GAAP
Income statement data
Turnover...................................... 175,389 161,826 101,180 83,732 108,564
Less:joint ventures........................... 1,171 13,764 17,614 15,428 16,804
------ ------ ------ ------ ------
Group turnover................................ 174,218 148,062 83,566 68,304 91,760
Total replacement cost operating profit (a)... 16,135 17,756 8,894 6,521 10,683
Replacement cost profit before
exceptional items (b)..................... 9,880 11,214 5,330 3,959 6,622
Profit for the year........................... 8,010 11,870 5,008 3,220 5,673
Per ordinary share (c): (cents)
Profit for the year:
Basic....................................... 35.70 54.85 25.82 16.77 29.56
Diluted..................................... 35.48 54.48 25.68 16.70 29.41
Dividends (d)............................... 22.00 20.50 20.00 19.75 18.04
Average number outstanding of 25 cents
ordinary shares (shares million).......... 22,436 21,638 19,386 19,192 19,185
Balance sheet data
Total assets.................................. 141,158 143,938 89,561 84,915 86,279
Net assets.................................... 74,994 74,001 44,342 43,573 43,603
Share capital................................. 5,629 5,653 4,892 4,863 4,330
BP shareholders' interest..................... 74,367 73,416 43,281 42,501 42,503
Finance debt due after more than one year..... 12,327 14,772 9,644 9,641 8,853
Debt to borrowed and invested capital (e)..... 14% 17% 18% 18% 17%
Other data
Per ordinary share: (cents)
Replacement cost profit before
exceptional items......................... 44.03 51.82 27.48 20.62 34.51
Net cash inflow from operating activities (f). 22,409 20,416 10,290 9,586 15,558
Net cash outflow from capital expenditure
acquisitions and disposals.................. 11,604 6,207 5,142 6,520 10,056
5
Years ended December 31,
-----------------------------------------------
2001 2000 1999 1998 1997
----- ----- ----- ----- -----
($ million except per share amounts)
US GAAP
Income statement data
Revenues...................................... 174,218 148,062 83,566 68,304 91,760
Profit for the period......................... 4,164 10,183 4,596 2,826 5,686
Comprehensive income.......................... 2,569 7,562 3,674 2,848 4,106
Profit per ordinary share (c)(g): (cents)
Basic..................................... 18.55 47.05 23.70 14.72 29.62
Diluted................................... 18.44 46.74 23.56 14.66 29.46
Profit per American Depositary
Share (c)(g): (cents)
Basic..................................... 111.30 282.30 142.20 88.32 177.72
Diluted................................... 110.64 280.44 141.36 87.96 176.76
Balance sheet data
Total assets.................................. 146,244 152,236 90,342 85,538 87,076
BP shareholders' interest..................... 62,322 65,554 37,838 37,334 37,504
Other data
Net cash used in investing activities......... 11,685 6,326 4,922 6,861 10,151
Net cash used in financing activities......... 5,853 7,852 3,332 2,161 3,449
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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 fundamental restructuring costs, interest
expense and taxation.
BP determines operating profit on a replacement cost basis, which
eliminates the effect of inventory holding gains and losses. For the oil
and gas industry, the price of crude oil can vary significantly from period
to period; hence the value of crude oil (and products) also varies. As a
consequence, the amount that would be charged to cost of sales on a
first-in, first-out (FIFO) basis of inventory valuation would include the
effect of oil price fluctuations on oil and products inventories. BP
therefore charges cost of sales with the average cost of supplies incurred
during the period rather than the historical cost of supplies on a FIFO
basis. For this purpose, inventories at the beginning and end of the period
are valued at the average cost of supplies incurred during the period
rather than at their historical cost. These valuations are made quarterly
by each business unit, based on local oil and product price indices
applicable to their specific inventory holdings, following a methodology
that has been consistently applied by BP for many years. Operating profit
on the replacement cost basis and a derivative measure, that is, profit
adjusted for depreciation and amortization arising from the fixed asset
revaluation adjustment and goodwill consequent upon the ARCO and Burmah
Castrol acquisitions, and adjusted for special items (non-recurring charges
and credits that are not classified as exceptional under UK GAAP), are used
by BP management as the primary measures of business unit trading
performance and BP management believes that these measures assist investors
to assess BP's underlying trading performance from period to period.
Replacement cost is not a US GAAP measure. The major US oil companies apply
the last-in, first-out (LIFO) basis of inventory valuation. The LIFO basis
is not permitted under UK GAAP. The LIFO basis eliminates the effect of
price fluctuations on crude oil and product inventory except where an
inventory drawdown occurs in a period. BP management believes that where
inventory volumes remain constant or increase in a period, operating profit
on the LIFO basis will not differ materially from operating profit on BP's
replacement cost basis.
Where an inventory drawdown occurs in a period, cost of sales on a LIFO
basis will be charged with the historical cost of the inventory drawn down,
whereas BP's replacement cost basis charges cost of sales at the average
cost of supplies for the period. To the extent that the historical cost on
the LIFO basis of the inventory drawn down is lower than the current cost
of supplies in the period, operating profit on the LIFO basis will be
greater than operating profit on BP's replacement cost basis. To the extent
that the historical cost on the LIFO basis of the inventory drawdown is
greater than the current cost of supplies in the period, operating profit
on the LIFO basis will be lower than operating profit on BP's replacement
cost basis.
(b) Replacement cost profit before exceptional items excludes profits and
losses on the sale of fixed assets and businesses or 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 (non-recurring charges and
credits that are not classified as exceptional under UK GAAP), are used by
the BP board in setting targets for and monitoring performance within the
Group. BP's management believes these indicators provide the most relevant
and useful measures for investors because they most accurately reflect
underlying trading performance.
6
(c) With effect from October 4, 1999 BP split (or subdivided) its ordinary
share capital. As a result, the number of ordinary shares held at the close
of business on Friday October 1, 1999, doubled, and holders of ADSs
received a two-for-one stock split. Comparative figures for 1997 and 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 1997 and 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 43.
(g) FASB Statement of Financial Accounting Standards No. 128 -- 'Earnings per
Share' (SFAS 128) was adopted for the accounting period ending December 31,
1997.
(h) The Group adopted Financial Reporting Standard No. 12 'Provisions,
Contingent Liabilities and Contingent Assets' with effect from January 1,
1999. Comparative figures for 1997 and 1998 have been changed accordingly.
Exchange Rates
The following table sets forth, for the periods and dates indicated,
certain information concerning the Noon Buying Rate for the pound in New York
City for cable transfers in pounds as certified for customs purposes by the
Federal Reserve Bank of New York. This is expressed in dollars per (pound)1.
At period end Average(a) High Low
------------- ------- ---- ----
Year ended December 31,
1997............................................ 1.63 1.64 1.70 1.58
1998............................................ 1.66 1.66 1.72 1.61
1999 ........................................... 1.62 1.61 1.68 1.55
2000 ........................................... 1.50 1.51 1.65 1.40
2001............................................ 1.45 1.44 1.50 1.37
Month of
September 2001.................................. 1.47 1.46 1.47 1.44
October 2001.................................... 1.45 1.45 1.48 1.42
November 2001................................... 1.43 1.44 1.47 1.41
December 2001................................... 1.45 1.44 1.46 1.42
January 2002.................................... 1.41 1.43 1.45 1.41
February 2002................................... 1.41 1.42 1.43 1.41
March 2002 (through March 26)................... 1.43 1.42 1.43 1.41
----------
(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 26, 2002 was $1.43 = (pound)1.
7
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. Until their shares have been
exchanged for BP ADSs, Amoco and ARCO shareholders do not have the right to
receive dividends.
At least until December 31, 2003, BP will announce dividends for Ordinary
Shares in US dollars and state an equivalent pounds sterling dividend. Dividends
on BP ordinary shares will be paid in pounds sterling and on BP ADSs in US
dollars. Prior to the fourth quarterly dividend of 1998 The British Petroleum
Company p.l.c. announced dividends in sterling. Foreign exchange rates may
affect dividends paid. However, when setting the dividend the directors are
mindful of dividend fluctuation in sterling terms.
The following table shows dividends announced by the Company per ADS for
each of the past five years, together with the 'refund' but before deduction of
withholding taxes as described in Item 10 -- Additional Information -- Taxation.
Refund means an amount equal to the tax credit available to individual
shareholders resident in the UK in respect of such dividend, less a withholding
tax equal to 15% (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 in London on the business day last preceding the day when the
directors announced their intention to pay the quarterly dividends for those
years.
Quarterly
---------------------------------
Dividends per American Depositary Share (a)(b) First Second Third Fourth Total
------ ------ ------ ------ ------
1997.......................... UK pence 19.7 20.6 20.7 21.5 82.5
US cents 31.9 33.6 34.6 35.3 135.4
Can. cents 44.1 46.4 48.6 50.5 189.6
1998.......................... UK pence 21.5 22.5 22.5 23.0 89.5
US cents 36.0 36.5 37.5 33.4 143.4
Can. cents 51.4 55.3 57.8 50.0 214.5
1999.......................... UK pence 20.5 20.8 20.2 20.8 82.3
US cents 33.3 33.3 33.3 33.4 133.3
Can. cents 48.7 50.1 48.6 48.5 195.9
2000.......................... UK pence 21.5 22.3 24.0 24.1 91.9
US cents 33.3 33.3 35.0 35.0 136.6
Can. cents 49.7 49.8 53.6 53.2 206.3
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
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(a) With effect from June 6, 1997 the Company split existing ADSs on a
two-for-one basis so that an ADS is now equivalent to six BP ordinary
shares.
(b) With effect from October 4, 1999 BP split (or subdivided) its ordinary
share capital. As a result, the number of BP ordinary shares held at the
close of business on Friday October 1, 1999, doubled, and holders of ADSs
received a two-for-one stock split. Comparative figures for 1997 and 1998
have been changed accordingly.
The share dividend plan, whereby holders of BP ordinary shares could elect
to receive new shares (out of unissued share capital) instead of cash dividends
at a rate equivalent to the sum of the net cash dividend and related tax credit,
was withdrawn following the third quarterly 1998 dividend.
A dividend reinvestment plan was introduced with effect from the fourth
quarterly 1998 dividend, whereby holders of BP ordinary shares can elect to
reinvest the net cash dividend in shares purchased on the London Stock Exchange.
This plan is not available to any person resident in the USA or Canada, or in
any jurisdiction outside the UK where such an offer requires compliance by the
Company with any governmental or regulatory procedures or any similar
formalities.
A dividend reinvestment plan is, however, available for holders of ADSs
through JPMorgan Chase Bank (formerly known as Morgan Guaranty Trust Company).
Future dividends will be dependent upon future earnings, the financial
condition of the Group, the Risk Factors set out below, and other matters which
may affect the business of the Group set out in Item 5 -- Operating and
Financial Review and Prospects.
8
RISK FACTORS
There is strong competition, both within the oil industry and with other
industries, in supplying the fuel needs of commerce, industry and the home.
The oil industry is particularly subject to regulation and intervention by
governments throughout the world in such matters as the award of exploration and
production interests, the imposition of specific drilling obligations,
environmental protection controls, control over the development and
decommissioning of a field (including restrictions on production) and, possibly,
nationalization, expropriation or cancellation of contract rights.
The oil industry is also subject to the payment of royalties and taxation,
which tend to be high compared with those payable in respect of other commercial
activities.
Exploration and production require high levels of investment and have
particular economic risks and opportunities. They are subject to natural hazards
and other uncertainties including those relating to the physical characteristics
of an oil or natural gas field.
Oil prices are subject to international supply and demand. Political
developments (especially in the Middle East) and the outcome of meetings of OPEC
can particularly affect world oil supply and oil prices.
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.
Crude oil prices are generally set in dollars while sales of refined
products may be in a variety of currencies. Fluctuation in exchange rates can
therefore give rise to foreign exchange exposures.
Sectors of the chemicals industry are also subject to fluctuations in
supply and demand within the chemicals market, with consequent effect on prices
and profitability, and to governmental regulation and intervention in such
matters as safety and environmental controls.
In addition to the adverse effect on revenues, margins and profitability
from any future fall in oil and natural gas prices, a prolonged period of low
prices or other indicators would lead to a review for impairment of the Group's
oil and natural gas properties. This review would reflect management's view of
long-term oil and natural gas prices. Such a review could result in a charge for
impairment which could have a significant effect on the Group's results of
operations in the period in which it occurs.
9
FORWARD LOOKING STATEMENTS
In order to utilize the 'Safe Harbor' provisions of the United States
Private Securities Litigation Reform Act of 1995, BP is providing the following
cautionary statement. This document contains certain forward-looking statements
with respect to the financial condition, results of operations and business of
BP and certain of the plans and objectives of BP with respect to these items.
These statements may generally, but not always, be identified by the use of
words such as 'will', 'expects', 'is expected to', 'may', 'should', '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 production volume, capacity or rate, the date or period in which
production is scheduled or expected to come on stream or a project or action is
scheduled or expected to be completed, (ii) the statements in Item 4 --
Information on the Company -- Strategy and Financial Targets with respect to the
Group's ratio of net debt to net debt plus equity, dividend policy, the manner
in which we use cash surpluses, the target to reduce the 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,
oil and gas prices, refining, marketing and chemicals margins, inventory and
product inventory levels, supply capacity, profitability, results of operation,
liquidity or financial position are all forward-looking in nature. By their
nature, forward-looking statements involve risk and uncertainty because they
relate to events and depend on circumstances that will occur in the future and
are outside the control of BP. Actual results may differ materially from those
expressed in such statements, depending on a variety of factors, including the
specific factors identified in the discussions accompanying such forward-looking
statements; future levels of industry product supply, demand and pricing;
political stability and economic growth in relevant areas of the world;
development and use of new technology and successful partnering; the actions of
competitors; natural disasters and other changes to business conditions; 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.
10
ITEM 4 -- INFORMATION ON THE COMPANY
GENERAL
Unless otherwise indicated, information in this Item reflects 100% of the
assets and operations of the Company and its subsidiaries which were
consolidated at the date or for the periods indicated, without the exclusion of
minority interests. Also, unless otherwise indicated, figures for business
turnover include sales between BP businesses.
BP was created on December 31, 1998 by the merger of Amoco Corporation of
the USA and The British Petroleum Company p.l.c. of the UK. Following this
merger, Amoco Corporation became a wholly owned subsidiary of The British
Petroleum Company p.l.c. and was renamed BP Amoco Corporation, and The British
Petroleum Company p.l.c. was renamed BP Amoco p.l.c. Amoco Corporation was
incorporated in Indiana, USA, in 1889 and The British Petroleum Company p.l.c.
was incorporated in England in 1909. 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.
Britannic House
1 Finsbury Circus
London EC2M 7BA
United Kingdom
Tel: +44(0)20 7496 4000
Internet address: www.bp.com
Business Overview
Our main businesses are Exploration and Production, Gas and Power, Refining
and Marketing, and Chemicals. Exploration and Production's activities include
oil and natural gas exploration and field development and production (upstream
activities), together with pipeline transportation and natural gas processing
(midstream activities). Gas and Power activities include marketing and trading
of natural gas, liquefied natural gas (LNG), natural gas liquids (NGL) and
power, the development of international opportunities that monetize gas
resources and involvement in select power projects. The activities of Refining
and Marketing include oil supply and trading as well as refining and marketing
(downstream activities). Chemicals activities include petrochemicals
manufacturing and marketing. In addition, we have a solar energy business which
is one of the world's largest manufacturers of photovoltaic modules and systems.
The Group provides high quality technological support for all its businesses
through its research and engineering activities.
We have well established operations in Europe, the USA, Canada, South
America, Australasia and parts of Africa. More than 70% of the Group's capital
is invested in Organization for Economic Cooperation and Development (OECD)
countries with just under one half of our fixed assets located in the USA, and
just under one third located in the UK and the Rest of Europe.
We believe that BP has a strong portfolio of assets in each of its four
main businesses:
-- In Exploration and Production we have substantial upstream interests
in the USA, with onshore natural gas production, oil and natural gas
production in the Gulf of Mexico and oil production in Alaska; the UK
where we are the largest producer of both oil and natural gas; Norway,
Canada, South America, Africa, the Middle East and Asia. We also have
significant midstream activities in support of these interests.
-- In Gas and Power, which has been reported as a separate business since
January 1, 2000, we have established and growing marketing and trading
businesses in North America (USA and Canada), the UK and Europe. Our
marketing and trading activities include 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 activities were transferred to
the Gas and Power business from Other Businesses and Corporate.
11
-- In Refining and Marketing we have a strong presence in the USA. We
market under the Amoco and BP brands in the Midwest, East, and
Southeast, and under the ARCO brand on the West Coast. In Europe we
have a strong retail position and increased our presence in 2000 by
buying out ExxonMobil's interest in the BP/Mobil European fuels
business. In 2000, we purchased Burmah Castrol, which significantly
increased our lubricants activities throughout the world. In addition
we have established or are growing businesses elsewhere in the world
under the BP brand.
-- In Chemicals we have a strong manufacturing and marketing base in the
USA and Europe, and are aiming to grow in the Asia Pacific region
where we already have interests in a number of production facilities.
We have a strong position in the technology and production of olefins
and derivative products (polyethylene, acetic acid and acrylonitrile),
a leading position in aromatics and derivative products (purified
terephthalic acid, paraxylene and metaxylene) and have strengthened
our polymers market position during 2001 through our deal with Solvay.
On April 13, 2000 BP and ARCO announced that they had received clearance
from the US Federal Trade Commission (FTC) for the combination of the two
companies and the combination was completed on April 18, 2000. The combination
has been accounted for as an acquisition under UK GAAP and as a purchase under
US GAAP. The results of ARCO have been included with effect from April 14, 2000,
the day following the approval by the US Federal Trade Commission of the
acquisition. ARCO stockholders received for each share of ARCO common stock held
as of April 17, 2000, 9.84 BP ordinary shares. Such shares were delivered in the
form of BP ADSs, or at the election of the holder of ARCO common stock, BP
ordinary shares.
On March 15, 2000 ARCO entered into an agreement to sell its Alaskan
businesses to Phillips Petroleum Company (Phillips) for approximately $6.5
billion cash subject to purchase price adjustments (and up to an additional $500
million based on the prices realized on production subsequent to December 31,
1999). Under the agreement ARCO agreed to sell all of the outstanding shares of
ARCO Alaska Inc., together with certain other subsidiaries of ARCO engaged
principally in the operation of ARCO's Alaskan businesses, along with certain
pipeline and marine assets associated with the transport of Alaskan crude oil.
The major portion of the sale closed on April 26, 2000.
BP acquired Burmah Castrol of the UK on July 7, 2000 for $4.8 billion
through a cash offer to shareholders of (pound)16.75 per share. The public share
price on the date of announcement, March 10, 2000, was (pound)9.65. Burmah
Castrol is a global marketer of specialized lubricant and chemical products and
services. Burmah Castrol had operations in over 50 countries and employed some
18,000 people.
In December 1999, we agreed with ExxonMobil on the principles under which
the BP/Mobil European joint venture would be dissolved in response to the
conditions of the European Commission's authorization of the Exxon and Mobil
merger. Under the agreement BP purchased ExxonMobil's 30% interest in the fuels
business for $1.5 billion with effect from August 1, 2000. In addition, the two
companies divided the assets of the lubricants business broadly in line with
their equity stakes (Mobil 51%, BP 49%). This dissolution was substantially
completed in 2000, thus increasing BP's share of all European markets where the
fuels joint venture was active.
On September 15, 2000 we acquired through ARCO the common stock of Vastar
held by minority shareholders at a price of $83 per share for a total
consideration of $1.6 billion. The public share price on the date of
announcement, March 16, 2000, was $71 7/16. Vastar became a wholly owned
subsidiary of the Company.
During 2000 BP made two strategic investments in China, one of the world's
fastest growing economies. BP invested $416 million in the China Petroleum and
Chemical Corporation (Sinopec) and $578 million in PetroChina in the initial
public offerings of both companies. BP has a 2.2% interest in each company.
Separately, BP announced plans to form joint ventures with both companies: in
natural gas marketing and fuels retailing with PetroChina and in fuels and
petroleum products marketing and chemicals with Sinopec. PetroChina and Sinopec
are two of China's major companies in the oil and chemicals businesses.
Following completion of the merger between BP and Amoco on December 31,
1998 and in the context of low oil prices at the time, BP undertook a strategic
and portfolio review in early 1999. This was completed in the Spring of 1999 and
resulted, among other things, in the development of an asset divestment
programme. The guiding principle of the strategic and portfolio review was to
concentrate the combined Group's operations on areas of competitive strength
and, in the upstream portfolio, to dispose of assets which would not be robustly
economic on the basis of conservative assumptions about future oil and natural
gas prices. Divestitures under this programme continued in 2000, and the
programme was completed in 2001.
12
Strategy and Financial Targets
In Exploration and Production our goal is to have significant shares of the
larger oil and natural gas fields where our supply costs can be fully
competitive with all other producers. The Gas and Power business is specifically
designed to extend our interests as the mix of world energy consumption shifts
in favour of natural gas. In Refining and Marketing we intend to invest in
geographic markets which are growing and in convenience retailing, while
focusing our refining on advantaged areas. In Chemicals we focus on excellence
in manufacturing and close links to both the supply of resources and actual and
potential demand growth.
As part of this strategy we developed a financial framework to maintain a
ratio of net debt to net debt plus equity, after adjusting equity for the fixed
asset revaluation adjustment and goodwill consequent upon the ARCO and Burmah
Castrol acquisitions, of around 20-30% and a dividend policy with the aim of
returning to shareholders around 50% of our replacement cost profit before
exceptional items and after adjusting for special items and acquisition
amortization, adjusted to mid-cycle operating conditions. Special items are
non-recurring charges and credits that are not classified as exceptional items
under UK GAAP. Acquisition amortization refers to depreciation relating to the
fixed asset revaluation adjustment and amortization of goodwill consequent upon
the ARCO and Burmah Castrol acquisitions. Mid-cycle operating conditions reflect
not only adjustments to hydrocarbon prices and margins, but also costs and
capacity utilization, to levels which we would expect on average over the long
term. If circumstances give us a larger surplus of cash than is required to fund
our capital programme and meet operational needs, the surplus may be used to pay
down debt to a level at the lower end of our gearing range and/or be returned to
shareholders.
In January 2002 BP adopted a new UK Financial Reporting Standard No. 19
'Deferred Tax' (FRS 19). This standard requires deferred tax to be accounted for
on a full rather than a partial provision basis. Prior years will be restated.
The new standard will increase the effective tax rate and reduce profit and
shareholders' interest. For example, if this new standard had been applied to
the reported results for 2001, the tax charge for the year would have increased
by $1,358 million to $6,375 million, and at December 31, 2001 there would have
been a reduction of $9,050 million in shareholders' interest. It will have no
effect on cash flow. In order to maintain the substance of the existing
financial framework, we are restating BP's target band of net debt to net debt
plus equity, after adjusting equity for the fixed asset revaluation adjustment
and goodwill consequent upon the ARCO and Burmah Castrol acquisitions, from
around 20-30% to around 25-35% and our target dividend payout ratio from around
50% to around 60% of our replacement cost profit before exceptional items and
after adjusting for special items and acquisition amortization, adjusted to
mid-cycle operating conditions.
Following completion of the ARCO and Burmah Castrol acquisitions in 2000 we
announced our 2001 targets which reflected the enlarged Group. Our cost
reduction target was to reduce the combined cost structure of the enlarged Group
by $5.8 billion by the end of 2001. Cost reductions also included the effect of
disposals on cash costs and lower exploration write-offs. Certain cash costs in
2000 and 2001 were adjusted to reflect cost levels which we would expect on
average over the long term. Total cost reductions achieved by the end of 2001
were $6.1 billion.
In February 2001, we announced further specific targets for 2001. We
targeted underlying performance improvements, which include cost savings and
volume growth, aiming to increase pre-tax results under mid-cycle operating
conditions, adjusted for acquisition amortization and special items, by $2.0
billion in 2001; growth in hydrocarbon production of 5.5%; and annual
investment, excluding acquisitions, in the $12-13 billion range. This level of
expenditure was intended to permit growth investment in Exploration and
Production to enable the business to achieve targeted production growth of 5.5%
each year in the medium term. This amount of investment is consistent with
historic levels for the enlarged Group.
We achieved underlying performance improvements of $2.0 billion and
production growth of 5.5% in 2001. Investment, excluding acquisitions, in 2001
was $13.2 billion and total investment was $14.1 billion.
We achieved the original 1999-2001 target of $10 billion proceeds from
disposals by end-2001. This excluded the FTC-mandated divestment of ARCO's
Alaskan interests and certain other assets.
In February 2002, we confirmed that our targets going forward remain
unchanged. Specifically, we aim to achieve pre-tax underlying performance
improvements, under mid-cycle operating conditions, of $1.4 billion through cost
savings and volume growth in 2002 and annual hydrocarbon production growth of
5.5% in the medium term. We continue to plan for annual investment, excluding
acquisitions, in the $12-13 billion range.
The targets disclosed above for 2002 and beyond are forward looking
statements and as such are subject to numerous risks and uncertainties which may
cause actual results to differ as described under Item 3 -- Risk Factors and
Item 3 -- Forward Looking Statements.
13
Financial and Operating Information
The following table summarizes the Group's turnover, results and capital
expenditure for the last five years and total assets at the end of each of those
years.
Years ended December 31,
-----------------------------------------------
2001 2000 1999 1998 1997
----- ----- ----- ----- -----
($ million)
Turnover............................... 175,389 161,826 101,180 83,732 108,564
Less: joint ventures................... 1,171 13,764 17,614 15,428 16,804
------- ------- ------- ------- -------
Group turnover (sales to third parties) 174,218 148,062 83,566 68,304 91,760
Total replacement cost operating profit 16,135 17,756 8,894 6,521 10,683
Profit for the year*................... 8,010 11,870 5,008 3,220 5,673
Capital expenditure and acquisitions... 14,124 47,613(a) 7,345(b) 10,362 11,420
Total assets........................... 141,158 143,938 89,561 84,915 86,279
--------
* After minority shareholders' interest
(a) Capital expenditure and acquisitions for 2000 includes $27,506 million for
the acquisition of ARCO and $8,936 million for acquisitions for cash, the
details of which can be found in Item 5 -- Operating and Financial Review
and Prospects -- Group Results.
(b) Capital expenditure and acquisitions in 1999 reflected reduced investment
following the merger of BP and Amoco.
All capital expenditure and acquisitions have been financed from cash flow
from operations, disposal proceeds and external financing.
Information for 2001, 2000 and 1999 concerning the profits and assets
attributable to the businesses and to the geographical areas in which the Group
operates is set forth in Item 18 -- Financial Statements -- Note 44.
The following table shows our production for the last five years and the
estimated proved oil and natural gas reserves at the end of each of those years.
Years ended December 31,
-----------------------------------------------
2001 2000 1999 1998 1997
----- ----- ----- ----- -----
Total crude oil production
(thousand barrels per day) (a).......... 1,931 1,928 2,061 2,049 1,930
Total natural gas production (million
cubic feet per day) (a)................. 8,632 7,609 6,067 5,808 5,858
Total estimated net proved crude oil
reserves (million barrels) (b).......... 7,217 6,508 6,535 7,304 7,612
Total estimated net proved natural gas
reserves (billion cubic feet) (b)....... 42,959 41,100 33,802 31,001 30,374
----------
(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 2001, 2,164 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), replacing 191% of the volume
produced. After allowing for production, which amounted to 1,133 mmboe, BP's
proved reserves increased to 14,624 mmboe. These proved reserves are mainly
located in the USA (42%), Trinidad and Tobago (16%) and the UK (14%).
----------
* Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1
million barrels.
14
Recent developments
With effect from February 1, 2002, BP acquired a majority stake in Veba Oil
from E.ON. Veba Oil owns Aral, Germany's biggest fuels retailer. BP paid E.ON
$1.63 billion in cash and assumed some $0.85 billion of debt in return for 51%
and operational control of Veba Oil. Additionally, E.ON can require BP to buy
the remaining 49% of Veba Oil for $2.40 billion in cash from April 1, 2002 under
the terms of an agreement between the two companies announced in July 2001.
That agreement envisaged part of the payment for Veba Oil being met by the
sale to E.ON of BP's wholly-owned subsidiary, Gelsenberg, which holds a 25.5%
stake in Germany's largest natural gas distributor, Ruhrgas. Although that sale
was prohibited by Germany's Federal Cartel Office, the decision is being
appealed to the German Economics Ministry, which is expected to rule in
mid-2002. If the German Economics Ministry were to approve the Ruhrgas
transaction, BP would sell its Ruhrgas stake to E.ON for an agreed $2.10
billion.
As a condition of regulatory approval of the deal BP is 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.
Separately BP and E.ON announced that they had agreed, subject to various
regulatory and other consents, to sell Veba's oil and natural gas exploration
and production business to Petro-Canada for $2.00 billion. From this sale BP
would receive $1.65 billion and E.ON the balance.
15
SEGMENTAL INFORMATION
The following tables show turnover and replacement cost profit by business
and by geographical area, for the years ended December 31, 2001, 2000, and 1999.
Years ended December 31,
-------------------------------------------------------------------------------------------
Turnover (a) 2001 2000 (b) 1999 (b)
----------------------------- ----------------------------- ----------------------------
Sales Sales to Sales Sales to Sales Sales to
Total between third Total between third Total between third
sales businesses parties sales businesses parties sales businesses parties
----- ---------- -------- ----- ---------- -------- ----- ---------- --------
($ million)
By business
Exploration and Production...... 28,229 19,660 8,569 30,942 16,787 14,155 19,133 10,063 9,070
Gas and Power................... 39,208 2,954 36,254 21,013 346 20,667 8,073 444 7,629
Refining and Marketing.......... 120,233 2,903 117,330 107,883 5,923 101,960 60,143 2,524 57,619
Chemicals....................... 11,515 233 11,282 11,247 216 11,031 9,392 342 9,050
Other businesses and corporate.. 783 -- 783 249 -- 249 198 -- 198
------ ------ ------ ------ ------ ------ ------ ------ ------
Group turnover.................. 199,968 25,750 174,218 171,334 23,272 148,062 96,939 13,373 83,566
======= ======= ======= ======= ======= =======
Share of joint venture sales.... 1,171 13,764 17,614
------ ------ ------
175,389 161,826 101,180
======= ======= =======
Sales Sales to Sales Sales to Sales Sales to
Total between third Total between third Total between third
sales areas parties sales areas parties sales areas parties
----- ---------- -------- ----- ---------- -------- ----- ---------- --------
($ million)
By geographical area
UK (c)....................... 47,618 13,467 34,151 45,400 10,970 34,430 30,223 4,406 25,817
Rest of Europe............... 36,701 7,603 29,098 20,553 1,911 18,642 5,973 641 5,332
USA.......................... 84,696 939 83,757 71,084 829 70,255 38,786 1,381 37,405
Rest of World................ 33,911 6,699 27,212 31,014 6,279 24,735 19,465 4,453 15,012
------ ------ ------ ------ ------ ------ ------ ------ ------
202,926 28,708 174,218 168,051 19,989 148,062 94,447 10,881 83,566
======= ======= ======= ======= ======= ======= ======= ======= ======
Share of joint venture sales
UK........................... 13 3,314 3,988
Rest of Europe............... 30 12,316 16,114
USA.......................... 318 270 155
Rest of World................ 810 686 342
------ ------ ------
1,171 16,586 20,599
Sales between areas -- 2,822 2,985
------ ------ ------
1,171 13,764 17,614
======= ======= =======
------------
(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) 1999 and 2000 have been restated to reflect the transfer of the NGL
business in North America from Refining and Marketing to Gas and Power.
(c) UK area includes the UK-based international activities of Refining and
Marketing.
16
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, 2001
By business
Exploration and Production.......... 11,858 373 186 12,417 195 12,612
Gas and Power....................... 337 -- 184 521 (1) 520
Refining and Marketing.............. 3,347 83 195 3,625 471 4,096
Chemicals........................... 21 (13) 120 128 (297) (169)
Other businesses and corporate...... (631) -- 75 (556) 167 (389)
------ ------ ------ ------ ------ ------
14,932 443 760 16,135 535 16,670
====== ====== ====== ====== ====== ======
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................................. 6,740 76 233 7,049 289 7,338
Rest of World....................... 3,956 371 277 4,604 532 5,136
------ ------ ------ ------ ------ ------
14,932 443 760 16,135 535 16,670
====== ====== ====== ====== ====== ======
Year ended December 31, 2000 (d)
By business
Exploration and Production.......... 13,399 384 229 14,012 119 14,131
Gas and Power....................... 409 -- 162 571 1 572
Refining and Marketing.............. 2,924 433 166 3,523 98 3,621
Chemicals........................... 576 (9) 193 760 (212) 548
Other businesses and corporate...... (1,152) -- 42 (1,110) 214 (896)
------ ------ ------ ------ ------ ------
16,156 808 792 17,756 220 17,976
====== ====== ====== ====== ====== ======
By geographical area
UK (c).............................. 3,629 106 38 3,773 12 3,785
Rest of Europe...................... 1,488 264 261 2,013 (19) 1,994
USA................................. 7,006 44 246 7,296 459 7,755
Rest of World....................... 4,033 394 247 4,674 (232) 4,442
------ ------ ------ ------ ------ ------
16,156 808 792 17,756 220 17,976
====== ====== ====== ====== ====== ======
Year ended December 31, 1999 (d)
By business
Exploration and Production.......... 6,686 175 122 6,983 (1,111) 5,872
Gas and Power....................... 258 -- 179 437 (1) 436
Refining and Marketing.............. 1,111 380 123 1,614 (319) 1,295
Chemicals........................... 561 -- 125 686 (257) 429
Other businesses and corporate...... (880) -- 54 (826) (592) (1,418)
------ ------ ------ ------ ------ ------
7,736 555 603 8,894 (2,280) 6,614
====== ====== ====== ====== ====== ======
By geographical area
UK (c).............................. 2,063 (1) 49 2,111 (237) 1,874
Rest of Europe...................... 548 381 238 1,167 (258) 909
USA................................. 2,803 13 185 3,001 (983) 2,018
Rest of World....................... 2,322 162 131 2,615 (802) 1,813
------ ------ ------ ------ ------ ------
7,736 555 603 8,894 (2,280) 6,614
====== ====== ====== ====== ====== ======
------------
(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 or termination of operations and in addition for 1999 include
fundamental restructuring costs.
(c) UK area includes the UK-based international activities of Refining and
Marketing.
(d) 1999 and 2000 have been restated to reflect the transfer of the NGL
business in North America from Refining and Marketing to Gas and Power.
17
EXPLORATION AND PRODUCTION
The activities of our Exploration and Production business include oil,
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 liquefied natural gas (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 2001
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 - and three major LNG plants - the
Atlantic LNG plant in Trinidad (BP 34%), in Indonesia through the joint venture
operating company Virginia Indonesia Co. (VICO) (BP 50%) and in Australia
through our share of LNG from the North West Shelf natural gas development (BP
16.7%).
Years ended December 31,
------------------------
2001 2000 1999
----- ----- -----
($ million)
Turnover (a)............................................. 28,229 30,942 19,133
Total replacement cost operating profit.................. 12,417 14,012 6,983
Total assets............................................. 69,572 65,904 44,967
Capital expenditure and acquisitions..................... 8,861 6,383 4,194
($ per barrel)
Average BP oil realizations.............................. 22.50 26.63 16.74
Average West Texas Intermediate oil price................ 25.89 30.38 19.33
Average Brent oil price.................................. 24.44 28.44 17.94
($ per thousand cubic feet)
Average BP natural gas realizations...................... 3.30 2.91 1.92
Average BP US natural gas realizations................... 3.99 3.72 2.06
Average Henry Hub gas price (b).......................... 4.26 3.90 2.27
----------
(a) Excludes BP's share of joint venture turnover of $666 million in 2001, $585
million in 2000, and $497 million in 1999.
(b) Henry Hub First of Month Index.
Strategy and Overview
Our strategy remains unchanged, targeting profitable production growth of
5.5% per year, underpinned by the following strategic elements: to have a
leading position in high quality basins around the world; to be a low-cost
supplier of oil, competitive with OPEC producers; and to supply low-cost gas to
markets. Evidence of 2001 delivery included capturing the remaining $500 million
of $3.1 billion of synergy cost savings from the merger of BP and Amoco and the
acquisition of ARCO, and achieving our production growth target of 5.5%. In the
future, we intend that our strategy will continue to be underpinned by three key
areas of focus: sustaining and maximizing the value of our base portfolio,
exploring for and developing resources in existing and emerging basins, and
upgrading the quality of our portfolio.
The first element underpinning our Exploration and Production strategy is
to maximize the value of our base portfolio by optimising production volumes and
driving efficiencies. We seek opportunities that are sustainable in the context
of fluctuating oil and natural gas prices.
We optimise production volumes through decline management and enhanced
recovery technologies to mitigate volume decline and increase ultimate
recoveries in mature fields. For example, during 2001:
-- We made extensive use of time-lapse 3-D seismic technology to
transform our in-field drilling programme. 21 operated fields are now
covered worldwide. In the North Sea, our increased reservoir
understanding led to additional production of 15 mboe/d compared to
2000 and should enable access to additional reserves in the region.
18
-- We continued to advance the technology associated with multi-lateral
wells and achieved an industry first on the Harding field with the
installation of sand control screens in such a well.
-- We successfully used the world's first commercial expandable liner
hanger in a producing well in the US Lower 48 States. This technology
should reduce drilling times and potentially reduce safety risks on
deep wells.
-- We advanced the use of cost efficient Coil Tubing Drilling to drill
multi-lateral wells, creating more economical access to the
development of Alaska's viscous oil.
-- We developed a technique in the North Sea that helps to identify
bottlenecks or constraints throughout the production system. During
2001 we began deploying this technique throughout our upstream
business. For example, in Azerbaijan we increased operating
efficiency by 2%.
Since 1998, our unit production costs (often referred to as unit lifting
costs) have decreased by 16%. We have driven operating efficiencies by:
-- Leveraging the economies of scale achieved through business
combinations and acquisitions.
-- Benchmarking, internally and externally, and sharing best practices
across the business units.
-- Working with key suppliers, contractors and partners.
The second element underpinning our strategy is to explore for and develop
resources in emerging basins, as well as in existing basins on a selective
basis, to provide growth for the future. We do this through focused large
projects and selective development of smaller satellite projects to take
advantage of existing infrastructure.
-- We are the largest leaseholder in the Gulf of Mexico and have
interests in nine of the ten largest Gulf of Mexico developments (BP
operates six). Our deepwater position in conjunction with integrated
development programmes should allow delivery of both near-term and
long-term production growth. In 2001, we announced the discovery at
Blind Faith (BP 77.5% and operator) and saw the start up of the
BP operated Nile Field (in addition to the non-BP operated Mica and
Crosby Fields). We also approved investment capital for three of the
four newest BP operated major field developments and began fabrication
activities. In 2002 we expect to begin production from King, King's
Peak, Princess (Phase I) and Horn Mountain fields. During 2003 to
2006, we expect to begin production at our NaKika, Princess (Phase
II), Thunder Horse (formerly known as Crazy Horse), Holstein, Mad Dog
and Atlantis fields. Production from these fields should contribute
substantially to our growth.
-- In Angola, we were involved in four new oil discoveries as well as the
Girassol project which went into production in December 2001. We also
sanctioned the Kizomba A and Jasmim developments.
-- In Trinidad, we approved construction of the world's largest methanol
plant and commenced expansion of the existing LNG plant by an
additional two trains. Trains are facilities for compressing,
liquefying, storing and offloading natural gas. BP will supply 50% of
the natural gas for the second train and 75% for the third train,
which we expect to come onstream in 2002 and 2003 respectively.
-- In Vietnam, we announced the construction of the $1.3-billion Nam Con
Son offshore natural gas project. The project is expected to develop
significant offshore natural gas for use by three generating plants to
provide electricity to Vietnam.
The third element underpinning our strategy is to upgrade the quality of
our asset portfolio by focusing investments in core areas (where we have either
critical mass and/or significant competitive position), selectively investing in
growth, and disposing of non-strategic assets. We have a rigorous process for
evaluating the economic merit and strategic fit of investment opportunities. For
example, prior to sanctioning, we test new projects in an effort to ensure that
they achieve a return in excess of the cost of capital at bottom of cycle prices
(that is $11 Brent).
In support of continued growth, 2001 capital expenditure, at $8.9 billion
(including $0.3 billion of acquisitions), was $2.5 billion higher than in 2000
($6.4 billion).
19
Examples of our investment and divestment activity include:
-- In June 2001, we entered into an agreement to dispose of our 9.5%
stake in the Kashagan discovery in Kazakhstan, after determining that
it did not enhance our competitive position.
-- We acquired a further 9.7% stake in the Tangguh LNG project in
Indonesia. This acquisition increased our share of Tangguh to about
50%. Tangguh is expected to be a long-term competitive supply source
helping to meet rising demand in the region.
-- In December 2001, we announced that the assets of Chernogorneft had
been returned to Sidanco (BP 11.2%). This completes the restructuring
of Sidanco with its debt substantially repaid and non-core assets
disposed of.
-- In January 2002, we acquired Statoil's interest in the Nam Con Son gas
project. This acquisition increased our interest in Block 06.1 from
26.6% to 35%. Our interest in Block 05.2 increased from 35% to 100%.
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 2001 were $1,102 million compared to
$1,295 million in 2000. About 65% of 2001 exploration and appraisal capital was
directed towards appraisal activity as we delineated the significant discoveries
made during 1999 and 2000. In 2001, we participated in 120 gross (48.4 net)
exploration and appraisal wells in 21 countries. The principal areas of activity
were Angola, Australia, Canada, Egypt, Norway, Trinidad, UK and the USA.
In 2001, we obtained upstream rights in several new tracts which are
expected to provide a foundation for continued exploration success. These
include the following:
-- In Egypt, we acquired a 16.67% interest in the West Med Block in the
Nile delta. We also increased our working interest in the Nile Delta
North Alex concession from 50% to 60%.
-- In the US Central Gulf of Mexico Lease Sale 178, we achieved a 74%
success rate. We were successful in obtaining 6 new deepwater blocks
including the primary block in a highly competitive prospect. Four of
these deepwater blocks were near existing discoveries. We also
achieved an 88% success rate in the Gulf of Mexico Shelf 178 licensing
round. In addition, we submitted and won bids for two blocks on the
Shelf in the Western Gulf of Mexico 180 Lease Sale.
-- In the UK, we were awarded operatorship and 66.67% working interest in
North Sea Block 204/18, the only block on which we bid in the UKCS
19th Licensing Round.
In 2001, we were involved in discoveries in Angola, Argentina, Australia,
Egypt, Pakistan, 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 2001 discoveries included the
following:
-- In the deepwater US Gulf of Mexico we announced a new discovery at
Blind Faith (BP 77.5%), which is approximately 20 miles northeast of
the Thunder Horse development, discovered in 1999.
-- Also in the deepwater US Gulf of Mexico, we announced the Aspen
discovery (BP 80% and operator). In early 2002, we announced that
Aspen would be 'fast tracked' to production and we reduced our
interest to 40%.
-- In Trinidad, we made another significant natural gas discovery in the
Cashima well (BP 100%).
-- In Angola, we were involved in three new oil discoveries: Violeta in
Block 17 (BP 16.7%), and Mavacola and Vicango in Block 15 (BP 26.7%).
20
-- In Australia, we participated in the Io natural gas discovery on the
Northwest Shelf (BP 13%).
-- In Egypt's Nile Delta we made two natural gas discoveries, Fayoum (BP
60% and operator) and Libra (BP 60% and operator).
-- In Argentina, our joint venture, Pan American Energy (BP 60%),
established Tres Picos as a major natural gas discovery (BP 60%).
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, 2001, 2000, and 1999 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 14,624 million barrels of oil equivalent
(mmboe) at December 31, 2001, an increase of 8% versus December 31, 2000.
Natural gas represents about 51% of these reserves. Reserve replacement through
extensions, discoveries, revisions and improved recovery exceeded production for
the eighth consecutive year with a ratio of 191%.
In 2001, total additions to the Group's proved reserves (excluding
purchases and sales and equity-accounted entities) amounted to 2,164 mmboe,
mostly through extensions to existing fields and discoveries of new fields. The
principal reserve additions were in Algeria, Angola, Azerbaijan, US Gulf of
Mexico, UK and Trinidad, following development approval of the rest of the In
Salah project, together with Kizomba A, Azeri-Chirag-Gunashli Phase 1, Thunder
Horse and Clair fields and the sanctioning of the Atlas Methanol plant.
Our total hydrocarbon production (including equity-accounted entities)
during 2001 averaged 3,419 thousand barrels of oil equivalent per day (mboe/d),
an increase of 179 mboe/d, or 5.5% compared with 2000, as production declines in
mature fields were more than offset by production start-ups and build-ups to
full production. About 40% of our production was in the USA and 23% in the UK.
21
The following tables show BP's production by major field for the three
years 1999 to 2001, and BP's aggregate estimated net proved reserves as at
December 31, 2001:
Crude oil (a)
Net production
--------------------
Production Field or Area Interest 2001 2000 1999
------------- -------- ----- ----- -----
(%) (thousand barrels per day)
Alaska (b) Prudhoe Bay* 26.3 123 146 202
Kuparuk 39.2 76 81 90
Milne Point* 100.0 45 40 42
Endicott* 67.9 19 21 25
Point McIntyre 32.2 10 16 25
Other Various 15 10 21
------ ------ ------
Total Alaska 288 314 405
------ ------ ------
Lower 48 States onshore Altura(b) Various -- 36 127
Other Various 213 182 133
------ ------ ------
Total Lower 48 States onshore 213 218 260
------ ------ ------
Gulf of Mexico (b) Mars 28.5 42 38 36
Troika 33.3 25 28 30
Pompano* 75.0 21 26 29
Other Various 155 105 44
------ ------ ------
Total Gulf of Mexico 243 197 139
------ ------ ------
Total USA 744 729 804
------ ------ ------
UK offshore (b) ETAP+ Various 80 85 80
Foinaven* 72.0 60 64 56
Forties* 96.1 51 53 66
Harding* 70.0 42 57 58
Schiehallion/Loyal* Various 40 44 36
Magnus* 85.0 37 47 48
Andrew* 62.8 25 33 43
Miller* 40.0 15 22 30
Other Various 99 89 123
------ ------ ------
Total UK offshore 449 494 540
Onshore Wytch Farm* 50.5 36 40 40
------ ------ ------
Total UK 485 534 580
------ ------ ------
Norway Draugen 18.4 40 38 37
Valhall* 28.1 22 23 27
Ula* 80.0 18 16 20
Gyda* 56.0 12 12 14
Netherlands and other Norway Various Various 8 1 2
------ ------ ------
Total Rest of Europe 100 90 100
------ ------ ------
----------
* BP operated.
+ BP operates the majority of the fields in this area.
22
Net production
--------------------
Production Field or Area Interest 2001 2000 1999
------------- -------- ----- ----- -----
(%) (thousand barrels per day)
Australia Various 16.7 40 37 23
Azerbaijan Azeri-Chirag-Gunashli* 34.1 35 30 32
Canada (b) Various Various 18 19 56
Colombia Cusiana/Cupiagua* 19.0 48 52 66
Egypt October 30.4 22 30 35
Other Various 69 78 95
Trinidad Various 100.0 48 47 49
Venezuela Various Various 54 46 30
Other (b) Various Various 60 51 21
------ ------ ------
Total Rest of World 394 390 407
------ ------ ------
Total Group 1,723 1,743 1,891
====== ====== ======
Equity-accounted entities
Abu Dhabi (d) Various Various 126 127 113
Argentina Various Various 50 40 41
Other Various Various 32 18 16
------ ------ ------
Total equity-accounted entities 208 185 170
------ ------ ------
Total Group and BP share
of equity-accounted entities (e) 1,931 1,928 2,061
====== ====== ======
----------
* BP operated.
+ BP operates the majority of the fields in this area.
December 31, 2001
------------------------------------------------------
Rest of Rest of
Estimated net proved reserves (a) UK Europe USA World Total
------ ------ ------ ------ ------
(millions of barrels)
Subsidiary undertakings
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
====== ====== ====== ====== ------
Equity-accounted entities 1,159
------
Total Group and BP share
of equity-accounted entities 8,376
======
23
Natural gas (a)(c)
Net production
--------------------
Production Field or Area Interest 2001 2000 1999
------------- -------- ----- ----- -----
(%) (million cubic feet per day)
Lower 48 States onshore (b) San Juan Coal* Various 615 563 427
Arkoma+ Various 219 94 111
San Juan Conventional+ Various 217 185 129
Tuscaloosa+ Various 187 171 175
Hugoton+ Various 180 170 162
Jonah* 79.1 109 77 57
Wamsutter* 70.5 100 100 92
Whitney Canyon+ Various 50 47 52
Anschutz Ranch East* Various 45 55 67
Moxa Arch* 41.0 43 52 77
Altura Various -- 34 118
Other Various 595 613 227
------ ------ ------
Total Lower 48 States onshore 2,360 2,161 1,694
Alaska Various Various 11 9 10
Gulf of Mexico (b) Marlin* 100.0 79 3 --
Matagorda Island 623* 44.0 76 78 99
Ram Powell (VK 912) 31.0 58 60 72
Matagorda Island 519* 82.0 40 56 39
Other Various 930 687 361
------ ------ ------
Total USA 3,554 3,054 2,275
------ ------ ------
UK offshore (b) Bruce* 37.0 256 201 175
Marnock* 62.0 125 148 79
Braes Various 100 99 76
West Sole* 100.0 81 89 97
Armada 18.2 71 75 77
Amethyst* 59.5 68 56 42
Ravenspurn South* 100.0 66 77 87
Britannia 9.0 65 41 --
East Leman* 48.4 59 58 42
Viking Complex 50.0 54 81 107
Vulcan 50.0 33 44 26
Other Various 730 678 487
Onshore Various Various 5 5 6
------ ------ ------
Total UK 1,713 1,652 1,301
------ ------ ------
Netherlands P/18-2* 48.7 47 52 63
Other Various 52 43 48
Norway Various Various 48 41 53
------ ------ ------
Total Rest of Europe 147 136 164
------ ------ ------
----------
* BP operated.
+ BP operates the majority of the fields in this area.
24
Net production
--------------------
Production Field or Area Interest 2001 2000 1999
------------- -------- ----- ----- -----
(%) (million cubic feet per day)
Rest of World
Australia Various 16.7 237 205 215
Canada (b) Kirby* 71.9 72 69 132
Brazeau River Gas* 70.0 71 63 41
Ricinus* 70.0 61 52 54
Marten Hills* 96.0 45 47 56
Leismer* 54.2 28 32 64
Other Various 307 319 342
China Yacheng* 34.0 108 77 --
Indonesia Pagerungan* 100.0 242 199 103
Sanga-Sanga 26.3 164 120 --
Other* 46.0 95 54 --
Sharjah Sajaa* 40.0 125 145 168
Other Various 35 39 38
Trinidad Mahogany* 100.0 529 530 367
Amherstia* 100.0 244 17 --
Immortelle* 100.0 128 232 207
Flamboyant* 100.0 52 69 92
Other* 100.0 58 37 115
Other (b) Various Various 272 198 69
------ ------ ------
Total Rest of World 2,873 2,504 2,063
------ ------ ------
Total Group 8,287 7,346 5,803
====== ====== ======
Equity-accounted entities
Argentina Various Various 236 187 145
Other Various Various 109 76 119
------ ------ ------
Total equity-accounted entities 345 263 264
------ ------ ------
Total Group and BP share
of equity-accounted entities 8,632 7,609 6,067
====== ====== ======
----------
* BP operated.
+ BP operates the majority of the fields in this area.
December 31, 2001
------------------------------------------------------
Rest of Rest of
Estimated net proved reserves (a) UK Europe USA World Total
------ ------ ------ ------ ------
(billions of cubic feet)
Subsidiary undertakings
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
====== ====== ====== ====== ------
Equity-accounted entities 3,216
------
Total Group and BP share
of equity-accounted entities 46,175
======
25
----------
(a) Net proved reserves of crude oil and natural gas, stated as of December 31,
2001, exclude production royalties due to others, and include minority
interests in consolidated operations.
(b) In 2001, BP purchased part of the interests of Statoil in Vietnam and the
interest of Inaquimicas in Cusiana/Cuipiagua 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.
In 1999, BP sold certain interests in Canada and Venezuela. At the end of
the year we purchased a significant part of Repsol YPF's share of the
assets of the dissolved Crescendo Resources partnership, a major natural
gas producer and processor in Texas and Oklahoma.
(c) Natural gas production volumes exclude gas consumed in operations.
(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 NGL from processing plants in which an interest is held of 78, 41
and 54 thousand barrels per day for 2001, 2000 and 1999, respectively.
26
United States
We are the largest producer of both liquids (crude oil and NGLs) and
natural gas in the USA.
Our 2001 US liquids and NGL production averaged 744 mb/d (thousand barrels
per day), an increase of 2% from 2000. Approximately 39% of our 2001 oil
production came from Alaska, 33% from the Gulf of Mexico, and the remainder from
onshore Lower 48 States. Our US natural gas production in 2001 was 3,554 mmcf/d
(million cubic feet per day), an increase of 16% over 2000.
Development expenditure in the USA (excluding pipelines) during 2001 was
$3,723 million, compared with $2,328 million in 2000, an increase of 60%.
Gulf of Mexico
Our largest area of growth in the USA is focused in the deepwater Gulf of
Mexico, which builds on our strong and stable US natural gas production base and
more than offsets the decline in our current principal oil producing fields in
Alaska. In 2001, our deepwater Gulf of Mexico liquids production was up over 23%
from 2000 levels, averaging 243 mb/d. Gas production was up over 34% from 2000
levels, averaging 1,183 mmcf/d.
Growth in 2001 was driven by the activity in the major facility hubs in the
deepwater Gulf of Mexico and comprised the following:
-- The Marlin hub (BP 80% and operator) reached record production rates
exceeding 60 mboe/d, including a peak natural gas rate of 325 mmcf/d.
In addition the Nile subsea development (BP 50% and operator) was
completed on schedule in 2001. The King and King West subsea
developments (BP 100% and operator) are scheduled for tie-in in 2002
and 2003 respectively.
-- The Pompano platform (BP 75% and operator) and subsea development
booked 30 mmboe gross reserves in two major prospects: Pompano Subsalt
and MC29. Production rates of 30 mmcf/d and 8 mboe/d gross from the
subsalt well have exceeded expectations. The Pompano facility was
upgraded to increase throughput by 30% in 2001. The Pompano facility
improved its baseline run time from under 90% in 2000 to 93% in 2001.
The Mica subsea development (BP 50%) was successfully tied-in to the
Pompano facility 60 days ahead of scheduled startup, and on budget.
Mica is the longest oil subsea tieback in the Gulf of Mexico to date
and production operations are on track.
-- Our active drilling and well work programme was successful at
arresting field decline in the Troika field (BP 33% and operator) and
we continued our work to optimise production configuration. Gross
production in 2001 averaged 108 mboe/d from 6 subsea development
wells.
-- Due to the continued successful development drilling results at Mars
(BP 29%) and the start-up of the Europa (BP 33.33%) and MC 764 (BP
67%) subsea developments, the Mars field surpassed the 250 mmboe
cumulative production milestone. Development drilling continued at
Mars Tension Leg Platform in order to maintain a full system at 220
mmcf/d and 200 mboe/d.
-- The Ursa platform (BP 23%) continued to ramp up in 2001 with six new
wells drilled and completed -- three Ursa wells and three from the
start-up of Crosby, a subsea tieback (BP 50%). Ursa is the largest
floating structure currently in the Gulf of Mexico and produced in
excess of 92 mb/d of oil and 269 mmcf/d of natural gas on average for
the year, achieving the 100 mmboe produced milestone in December 2001.
In 2002 we expect to begin production from the Princess field (BP
23%).
-- The 300 mmboe Diana/Hoover (BP 33%) Western Gulf of Mexico basin
opening development project began operations in 2000. The development
consists of a floating deep-draft Caisson Vessel (DDCV) host located
over the Hoover field in 4,500 feet of water. Diana, a five well
subsea development, is tied back to the Hoover DDCV. The Hoover DDCV
is the deepest floating production facility to date in the Gulf of
Mexico. Production rates at year end averaged over 75 mboe/d.
Providing a strong foundation to our offshore portfolio are our Gulf of
Mexico Shelf operations. BP accounts for 8% of the Gulf of Mexico Shelf
production (Offshore Louisiana and Texas), which supplies 1/6th of the US
natural gas market. We operate more than 200 platforms and 700 wells in up to
1,500 ft water depth. The Shelf is a mature basin with high decline rates,
averaging 30-40% per year. In spite of that, we have maintained flat production
over the last several years by utilizing advanced seismic technologies,
reservoir studies, new completion technologies, and higher operating
efficiencies. In 2001, we produced 198 mboe/d. We operated 12 rigs and drilled
61 operated wells.
Alaska
In Alaska, crude oil production in 2001 declined to 288 mb/d from a 2000
level of 314 mb/d. Despite this decline, we expect 2002 production in Alaska to
be higher than 2001 due to the start-up of the Northstar field.
27
The current status of activity in Alaska is as follows:
-- Development is ongoing to mitigate the production decline at Alaska's
largest producing field, Prudhoe Bay (BP 26.3% and operator). The
overall observed decline rate for the Greater Prudhoe Bay Unit in 2001
was 16%. Production was characterized by continued decline in the
Ivishak Producing Area and Greater Point MacIntyre Area, offset by
increased production from new satellite fields.
-- The Borealis and Northwest Eileen fields (BP 26.3% and operator) came
on line in the third quarter of 2001. Annualised satellite production
averaged 13 mb/d (gross) for the year. By year-end, satellite field
production had ramped up to 37 mb/d (gross). The satellite-drilling
programme resulted in 19 new wells in the unit. The active drilling
programme also resulted in the discovery of the new Orion Satellite.
-- Continued development of the Greater Prudhoe Bay Satellite fields in
2002 is expected to result in 34 additional wells and potential
sanctioning of development of the Orion Satellite.
-- The Prudhoe Bay field continued an active infill drilling programme in
2001 with approximately 93 new and sidetracked wells. In 2002, we
anticipate a 10% increase in the number of new and sidetracked wells.
-- The Northstar oil field (BP 99.1% and operator) was brought on line in
October 2001 at a planned initial rate of 8 mb/d net and by December
had reached a rate of 28 mb/d. The field is expected to reach a
plateau rate of 50 mb/d net. BP's share of the full development cost
is expected to be around $900 million.
-- Plans for the Point Thomson natural gas condensate field on the
eastern North Slope have progressed in 2001. BP holds approximately
32% of this natural gas condensate field. While the field is expected
ultimately to support a major natural gas pipeline off the North
Slope, we are reviewing a project with natural gas sales as a future
option, although no pipeline yet exists.
-- The Meltwater satellite development project at the Kuparuk field (BP
39.2%) began production in the fourth quarter of 2001. The field is
expected to peak at about 20 mb/d gross.
-- In January 2002, we announced that we were suspending plans to develop
the offshore Liberty field in favour of enhancing production at
existing, large North Slope fields.
Lower 48 States
In the Lower 48 States, we remain the largest producer of natural gas,
accounting for approximately 7% of total US onshore natural gas production.
Production comes from a large number of fields situated principally in the
states of Colorado, Kansas, Louisiana, New Mexico, Oklahoma, Texas and Wyoming.
In 2001, our production of oil and natural gas in the Lower 48 States was
620 mboe/d, up from 591 mboe/d in 2000 due to the full-year effect of the
ARCO/Vastar acquisition in 2000. In 2001, we operated 34 drilling rigs and
drilled 461 wells, adding reserves to replace 100% of production. Crude oil and
NGL production was 213 mb/d, up 17% from 2000 levels. Natural gas production was
2,360 mmcf/d in 2001, up 9% from 2000 production.
Our production in the onshore Lower 48 States is derived primarily from the
following assets:
-- In the mid-continent states (Kansas, Oklahoma, Texas and Louisiana)
our operations produced 1,001 mmcf/d of natural gas and 11 mb/d of oil
in 2001. Examples of improved efficiency to maintain rate in mature
areas include:
-- Western Kansas (Hugoton and Panoma fields) -- In 2001, through
aggressive optimization of well operating conditions, we managed
to hold production approximately flat in the Hugoton field. The
Hugoton field is the largest natural gas field in the Lower 48
States and has previously experienced decline rates approaching
20%.
-- Oklahoma and Texas Panhandles (Anadarko Basin) -- We drilled and
completed a 40 mmcf/d well, one of the biggest producing wells in
recent history in the basin.
28
-- Louisiana (Tuscaloosa Trend) -- The Tuscaloosa asset set a new field
production record of 373 mmcf/d in November 2001. The newly completed
Martin No.1 well made a significant contribution to this record with a
stabilized initial production rate of 80 mmcf/d.
-- Southeast Texas -- In the Northeast Thompsonville field, we
successfully deployed the world's first commercial expandable liner
hanger in a producing well. This technical innovation has the
potential to reduce significantly drilling times (by reducing the
number of trips) and safety risks (through its simpler design and
ability to withstand higher pressures) on deep wells.
-- The Southern Wyoming (Overthrust Belt, Greater Green River Basin)
operations produced 384 mmcf/d of natural gas and 9 mb/d of oil in
2001. Drilling activity has significantly increased in conjunction
with a five-year drilling programme comprising more than 600 wells,
primarily in the Jonah and Wamsutter fields. The 2001 drilling
programme broke several field records, including most wells spudded in
a single month (15), best drilling time (7.3 days/10,000 ft), and the
deepest well drilled worldwide (9,500 ft) utilizing casing as the
drill string. In other parts of the Greater Green River Basin, we
achieved production growth of 20% through a combination of heavy
drilling activity in the Jonah field and successful production base
management in Moxa.
-- Colorado and New Mexico (San Juan Basin Coal and Conventional Gas
fields) operations produced 832 mmcf/d of natural gas in 2001.
Specific activities included the implementation of the Fruitland
Coalbed Methane 160 acre infill programme and the final integration of
BP and Vastar operations and personnel.
-- In the Permian Basin, 2001 production averaged 151 mmcf/d of natural
gas and 55 mboe/d of liquids, an increase of 3% from 2000.
United Kingdom
We are the largest producer of both oil and natural gas in the UK. Our 2001
UK oil production of 485 mb/d was 49 mb/d lower than in 2000. Our UK natural gas
production increased 4% from 1,652 mmcf/d in 2000 to 1,713 mmcf/d in 2001. The
North Sea is a mature basin.
Our development expenditure in the UK (excluding pipelines) grew by 15%
from $808 million in 2000 to $930 million during 2001. Significant 2001 activity
included the following:
-- The Clair field Phase I development (BP 28.6% and operator) was
sanctioned by BP and its partners in September, at an estimated net
cost to BP of approximately $270 million. Currently the largest
undeveloped resource on the UK Continental Shelf, the field was
discovered in 1977 some 75 kilometres west of the Shetland Islands in
140 meters of water but was not developed due to technical
difficulties. Advances in technology now make development of Clair
commercially feasible. First production is expected in late 2004, with
peak production rates of 20 mboe/d net in 2006.
-- The Foinaven field (BP 72% and operator), also west of the Shetland
Islands in 600 meters of water, achieved a new production high of 138
mboe/d gross. This was in part due to production from the first two of
five wells in Phase II, and in part due to first production from the
East Foinaven field (BP 43% and operator) which began producing in
September. East Foinaven is a subsea development consisting of three
wells tied back to the Foinaven main field facilities. Starting in
2002, natural gas is planned to be exported from Foinaven and East
Foinaven to Magnus through BP's newly constructed West of Shetland
Pipeline System.
-- The natural gas pipeline which will support the Magnus Enhanced Oil
Recovery Project (EOR) was completed. This pipeline will link the
Magnus field (BP 85% and operator) to the deepwater west of Shetland
Islands fields via the Sullom Voe Terminal Processing plant. Surplus
natural gas from the Atlantic Margin fields is expected to flow
beginning in mid-2002 into the Magnus reservoir and is expected to
recover trapped oil which is expected to extend field life by some ten
years and enable production at a plateau level of around 60 mboe/d
gross until 2006. Surplus natural gas will be sold to market via
existing pipelines.
-- The Bruce field (BP 37% and operator) saw the commencement of a
two-year infill drilling programme. The second phase development of
the Keith field (BP 35%) was sanctioned.
29
-- Harding field (BP 70% and operator) produced at a rate of 60 mb/d
(gross) with the main part of the cluster (Harding South and Central)
coming off plateau but being offset by production from satellite
fields. The first infill well, part of a programme to fully exploit
Harding South and Central reservoirs, was completed during the fourth
quarter giving an additional 10 mb/d gross to the field. This well was
the first UK Continental Shelf multilateral well with expandable sand
screens. Further infill wells are expected to be drilled in 2002.
-- Maclure field development (BP 33.33% and operator) was sanctioned in
December 2001 and is currently awaiting UK Government approval.
Maclure is a subsea development with initial production rates of 12
mb/d oil and 3.5 mmcf/d natural gas expected to start up in mid-2002.
-- Eastern Trough Area Project (ETAP) production continued at high levels
(108 mboe/d net) during 2001 despite the onset of natural decline in
some of the initial fields (Machar in particular). During 2001 we
increased our interest to 37.8% in the Madoes field (formerly known as
Tornado) via an equity purchase from Phillips. We also sanctioned
development of both Madoes and Mirren via subsea tieback to the ETAP
central processing facility. First production from these satellite
fields is expected in late 2002.
-- In the Southern North Sea area, there were a number of satellite and
infill well activities. The North Davy well (BP 22% and operator),
drilled in 2000, was successfully tied in and produced. The Amethyst
Flowers well (BP 59.5% and operator) was also completed. The Hoton
Project (BP 100% and operator) was completed on schedule with first
production in December 2001.
-- A successful appraisal well was drilled to test an extension to the
Vanguard field (BP 50%) and a development plan for the new field is
under preparation.
-- The Shearwater Project (BP 27.5%) started production in mid-2001.
Problems with plant and a number of wells were experienced, with net
production averaging 7 mboe/d for the year. Production was shut down
in December 2001 due to cracks in condensate pipework. We continue to
work with the operator to restart production and to complete required
remedial work on wells and pipework aimed at establishing steady state
production during 2002.
Rest of Europe
Development expenditure in the Rest of Europe grew by 77% from $153 million
in 2000 to $271 million in 2001.
Our Norwegian production increased from 95 mboe/d in 2000 to 108 mboe/d in
2001. Start-up of our Tambar field in July as well as new wells and increased
efficiency at Ula are the main contributors to the increase. In addition,
Draugen has increased field capacity in 2001. The natural decline of other
fields has been offset by new wells at Valhall, the gas lift project at Hod and
equal priority for Gyda at Ekofisk. Net production in 2001 was 40 mboe/d from
Draugen (BP 18.4%), 26 mboe/d from Valhall (BP 28.1% and operator), 19 mboe/d
from Ula (BP 80% and operator), 14 mboe/d from Gyda (BP 56% and operator), 6
mboe/d from Tambar (BP 55% and operator) and 2 mboe/d from Hod (BP 25% and
operator). Appraisal activity included the Skarv oil and natural gas prospect
(BP 30% and operator). The third Skarv well including a sidetrack was completed
in June with positive results supporting a combined oil and natural gas
development.
In the Netherlands, we are continuing to expand our role in natural gas
storage services with the production and downstream natural gas marketing
businesses working in close co-operation. The Peak Gas Installation, which came
on stream in 2000, is a natural gas storage facility designed to assist in
meeting peak demand requirements from consumers in the Netherlands. This
installation has a storage capacity of 17,000 mmcf and is capable of withdrawing
1,270 mmcf/d.
Rest of World
The Group's net share of oil production from the Rest of World, including
joint ventures and associated undertakings, increased to 602 mb/d in 2001 from
575 mb/d in 2000. Excluding joint ventures and associated undertakings
production was 394 mb/d in 2001, up from 390 mb/d in 2000. Areas of oil
production in 2001 were Abu Dhabi, Algeria, Angola, Argentina, Australia,
Azerbaijan, Bolivia, Canada, China, Colombia, Egypt, Indonesia, Pakistan, Qatar,
Russia, Sharjah, Trinidad and Venezuela.
Our share of natural gas production from the Rest of World, including joint
ventures and associated undertakings, increased to 3,218 mmcf/d in 2001 from
2,767 mmcf/d in 2000. Excluding joint ventures and associated undertakings
production averaged 2,873 mmcf/d in 2001, up from 2,504 mmcf/d in 2000. The
largest part of 2001 production came from Trinidad and Tobago and from
Indonesia, with the remainder from Argentina, Australia, Bolivia, Canada, China,
Colombia, Egypt, Pakistan and Sharjah.
30
Canada, the Caribbean and South America
Development expenditure in the Rest of World (excluding pipelines) was
$1,934 million in 2001, compared with $1,274 million in 2000, an increase of
52%.
-- In Canada, our portfolio covers a wide range of geographic areas,
geological structures and infrastructure. Development activities
within Canada are focused on opportunities to maintain production
rates and position for growth within our existing core operating areas
in the provinces of Alberta and British Columbia. In 2001, production
was flat at 119 mboe/d, of which almost 85% was natural gas production
(584 mmcf/d). BP has interests in 25 fields and operates approximately
1,200 wells (gross). During 2001 we operated 18 drilling rigs and
drilled over 124 wells (gross).
Significant activity in South America in 2001 included the following:
-- The Colombian business is made up of mature producing assets
(Cusiana/Cupiagua fields), assets under appraisal/development (Recetor
and Florena fields) and a large prospect at the initial exploration
stage (Niscota). Production for 2001 was 49 mboe/d. In 2001, the
Florena field was successfully entered, ahead of schedule and with
better than expected production rates. In addition, the successful
Phase 1A development of the Recetor area, Cupiagua's northern
extension, resulted in an additional commercial area and the
acceleration of the overall Recetor development. BP has deepened its
Recetor acreage equity from 63% to 80% (25% to 32% production equity).
-- In the Southern Cone, business in Argentina and Bolivia is conducted
via our participation in Pan American Energy (PAE) in Argentina (BP
60%), which owns Empresa Petrolera Chaco in Bolivia.
Growth in 2001 was achieved in both oil and natural gas operations.
These entities produced 50 mb/d of oil and 236 mmcf/d of natural gas
(net to BP). Oil production increased by nearly 25% over 2000, largely
as a result of a major drilling programme in Golfo San Jorge. Activity
included infill and appraisal wells, water floods and electrification.
Gas production increased by over 26% over 2000 with contributions from
all operations. The most significant increase arose in Cerro Dragon
and in the Northwest Basin where the first phase development of the
Acambuco field came on stream during the first quarter of 2001.
Despite a severely depressed economy in Argentina, PAE was successful
in increasing its natural gas market share from 9% to 12% during 2001.
PAE also has significant interests in natural gas liquids plants, oil
and natural gas pipelines, electricity generation plants, and other
midstream infrastructure. Fiscal reform in Argentina is currently
being debated and PAE management is actively involved in ongoing
negotiations and in assessing the impact on our growth plans.
-- In Venezuela we produced 54 mboe/d from four core assets during 2001.
These 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 government oil company, PDVSA.
At the partner-operated Lake Maracaibo field (BP 27%), a slower than
anticipated repressurization of the reservoir delayed and increased
the uncertainty of oil production relative to the reactivation
investment. Therefore we revised our reserve estimates downwards and
recognized a charge for impairment of $175 million.
-- In Trinidad, production for 2001 reached 223 mboe/d (78% natural gas
and 22% liquids) for 2001, up nearly 12% on 2000 production levels.
Gas sales increased by 14% and liquid production increased by more
than 3%. The increase in natural gas sales was principally due to
increased purchases by The National Gas Company of Trinidad and
Tobago. In late 2001, BP entered into an agreement to restructure
certain natural gas contracts thereby providing for greater
flexibility in choosing the field from which to source the natural
gas. Major drilling activity in 2001 took place in the Mahogany and
Amherstia fields, including several high rate wells one of which
flowed at a rate of 200 mmcf/d.
Africa and the Middle East
Significant 2001 activity in Africa and the Middle East included:
-- In Angola Block 17 (BP 16.7%), the Girassol project went into
production in December 2001 and ramp-up of production has gone well.
The development of Jasmim, a tie-back to the Girassol hub, was
approved. Additional development studies in Block 17, Rosa and Dalia,
are well progressed.
31
Another significant milestone in Angola was achieved on Block 15
non-operated activities where the development approval of the
large-scale Kizomba A (BP 26.7%) development (July 2001 sanction) was
secured with first oil anticipated in 2004. Appraisal drilling
commenced during the fourth quarter of 2001 with the aim of securing
additional volumes to tie back to the Kizomba A hub and further
improving Block 15 operating efficiencies. Future growth potential was
also underpinned by progress on engineering studies for Kizomba B
developments.
In Angola's BP operated Block 18 (BP 50% and operator), work has
progressed well in the development engineering to determine the
optimum development strategy for the six discoveries.
In Block 31 (BP 26.6% and operator), a dry hole was drilled and there
is activity planned in 2002 to further delineate the Block.
-- In Egypt, our oil production operations are carried out by the Gulf of
Suez Petroleum Company (Gupco), a joint operating company with the
Egyptian General Petroleum Company (EGPC). Gupco operates seven
production sharing contracts in the Gulf of Suez and Western Desert,
encompassing more than forty fields. During 2001, Gupco produced 183
mb/d (87 mb/d net), almost 30% of Egypt's oil production, as well as
68 mmcf/d (33 mmcf/d net) of natural gas. Production operations were
interrupted by a fire on the October platform in May 2001; October was
fully back on line by the fourth quarter.
Gas production in Egypt grew 39% to 156 mmcf/d (net) with Ha'py (BP
50%) and Baltim (BP 50%) fields ramping up and the Temsah (BP 50%)
natural gas field start-up was on schedule in March 2001.
Collectively, we have agreements in place to supply 352 mmcf/d
(working interest) to the domestic Egyptian market from these and
other Nile Delta fields. The Akhen (BP 50%) drilling and development
project was progressed in 2001 and the field is on schedule for
production start-up in 2002.
In Egypt, BP has a 33% interest in the Med NGL project. The project
involves the construction of a 1.1 bcf/d NGL plant. The plant is
expected to start production in 2004, and should produce 280 thousand
tonnes per annum (mtpa) of propane, 330 mtpa of LPG, and 2.7 mb/d of
condensates.
-- 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
expiring in 2014 and 2018, respectively. Production in Abu Dhabi was
126 mb/d, down from 2000 as OPEC cuts made an impact throughout 2001.
-- In addition, Sharjah natural gas production was down 13% on 2000 to
160 mcf/d, although the field decline would have been more severe
without plant modifications and drilling in 2001.
-- In Algeria, BP and the Algerian state company, Sonatrach, completed
natural gas sales terms and let engineering, procurement and
construction contracts in August 2001 for the In Salah project (BP
65%). The first stage comprises a development of four of the seven
deep Saharan natural gas fields; the development is expected to cost
$2.7 billion gross. In Salah is expected to supply the fast growing
markets of southern Europe with up to 320 bcf annually with first
deliveries forecast for 2004.
-- The In Amenas (BP 100%) pre-project programme was progressed with
contract bids for engineering, procurement and construction analysed,
and final stage appraisal/pre-development drilling. The Rhourde el
Baguel (BP 60%) gas injection facilities redevelopment has been
completed.
-- In June 2001, we signed a memorandum of understanding to take a major
interest in Saudi Arabia's largest natural gas development and the
first significant hydrocarbons project for 25 years in which the Saudi
government has invited foreign companies to participate.
-- In Iran we are carrying out studies of a potential redevelopment plan
for the Ahwaz Bangestan fields and are conducting a feasibility study
of a South Pars LNG project. At this stage, no agreements have yet
been concluded that commit BP to any significant investments in Iran.
Asia
Significant 2001 activity in Asia (including the former Soviet Union)
included:
-- BP, as operator of the Azerbaijan International Operating Company
(AIOC), manages and has 34.1% interest in the Azeri-Chirag-Gunashli
(ACG) oil fields in the Caspian Sea, offshore Azerbaijan. In 2001, ACG
production grew to 35 mb/d net (119 mb/d gross) from the Chirag 1
platform and this early production is expected to plateau at 37 mb/d
(127 mb/d) in 2002. The next step in the development of the ACG field
was achieved in 2001 with the approval in August of ACG Phase 1 ($3.4
billion estimated gross capital expenditure). First oil is expected in
2005. Development engineering for ACG Phase 2 and Phase 3 was also
progressed as the follow-on phases of development.
32
BP is also the operator of the Shah Deniz natural gas field with a
25.5% interest. Project definition progressed in 2001, predicated on a
staged development concept. Shah Deniz Stage 1 is anticipated to come
on-stream in 2005 comprising an offshore production facility, with
platform and subsea wells, separate natural gas and condensate lines
to shore, a processing terminal at Sangachal and a new 42-inch
diameter natural gas line through Azerbaijan and Georgia to Turkey
along the Baku-Tbilisi-Ceyhan route up to the Georgian/Turkish border.
Boru Hatlari ile Petrol Tasima (BOTAS) in Turkey and State Oil Company
of the Azerbaijan Republic (SOCAR) signed a Sales and Purchase
Agreement (SPA) in March 2001. It is anticipated that this SPA, with
appropriate amendments, will be assigned in full to Shah Deniz
interest owners. Transit agreements with the Governments of
Azerbaijan, Georgia, and Turkey to support the natural gas export
pipeline (South Caucasus Pipeline) and natural gas sales, have also
been completed.
-- In December, we announced that we had secured our ownership interest
in the Russian integrated oil company A O Sidanco (Sidanco) and
overseen the rightful return of the Chernogorneft producing assets
during the fourth quarter of 2001. This completes the restructuring of
Sidanco with its debt substantially repaid, and non-core assets
disposed of. We believe that Sidanco is now positioned as a low cost
Russian producer. As a result of transactions in 2001, we increased
our production and beneficial interest to an effective 11.2% equity
interest in Sidanco. We have a three-year management contract for
Sidanco, acting with effectively a 25% voting interest. BP-seconded
personnel hold a number of the senior management positions and a BP
executive acts as Chairman of the Sidanco Board of Directors. We also
have an interest in Kovytka (BP 28.4%), an undeveloped East Siberian
natural gas field.
-- In Kazakhstan, we agreed to dispose of a non-strategic portion of our
portfolio by selling surplus capacity in the Caspian Pipeline
Consortium (CPC) (BP 5.75%) pipeline. We also agreed to sell our
interest in the Kashagan field.
-- In Indonesia, BP is now the largest supplier of natural gas to Java.
In addition, the VICO (BP 50%) operated Sanga Sanga production sharing
contract (PSC) provides 30% of the natural gas feed into the Bontang
LNG operation for export and East Kalimantan domestic consumption. Our
share of Indonesian production in 2001 was 21 mb/d of liquids, 236
mmcf/d of natural gas sold to the Bontang LNG plant and 339 mmcf/d
sold domestically in Indonesia. Under the terms of the PSC, the
reported production entitlement varies inversely with price to effect
recovery of costs which are fixed in US dollars; as prices decrease
therefore, a higher entitlement is received.
-- In China, BP operates the Yacheng natural gas field and the Liu Hua
oil field. Yacheng supplies 100% of the natural gas supply into Hong
Kong where it is sold to Castle Peak Power Company (CAPCO) under a
long-term contract. Excess natural gas and liquids are piped to Hainan
Island where the natural gas is sold to the Fuel and Chemical Company
of Hainan also under a long-term contract. The QHD oil field (operated
by CNOOC) began production in October and is expected to reach plateau
during the fourth quarter of 2002.
BP's Hedong Coal Bed Methane (CBM) (BP 70%) project is located in the
Ordos Basin in Shanxii province approximately 800 kilometers southwest
of Beijing. BP has met all the contractual obligations of the
Production Sharing Agreements and, after two years of pilot production
testing, has decided to exit the project for technical reasons.
-- In Vietnam, BP (35% and consortium leader) and partners signed key
elements of a $1.3 billion integrated natural gas project at the end
of 2000. Construction of the Block 06.1 natural gas development and
associated infrastructure commenced in early 2001 and is now well
advanced. This scheme is intended to provide the basis for clean,
reliable gas-fired power generation in southern Vietnam. First
production is planned for late 2002.
-- In Pakistan, BP is the largest foreign operator producing 50% of the
country's oil and 10% of its natural gas on a gross basis.
Midstream Activities
Oil and Natural Gas Transportation
The Group has direct or indirect interests in certain crude oil
transportation systems, the principal ones of which are the Trans Alaska
Pipeline System in the USA and the Forties Pipelines System in the UK sector of
the North Sea. We also operate and have an interest in the Central Area
Transmission System for natural gas in the UK sector of the North Sea. Our
onshore US crude and product pipelines and related transportation assets are
included under 'Refining and Marketing'. Our gas marketing business is described
under 'Gas and Power'.
33
-- The Trans Alaska Pipeline System (TAPS) consists of a 48-inch diameter
crude oil pipeline running approximately 1,300 kilometers from Prudhoe
Bay to a tank farm and marine terminal at the ice-free port of Valdez
on Alaska's southern coast. The Alyeska Pipeline Service Company
operates the pipeline and terminal at Valdez. As part of the equity
alignment related to ownership of the Prudhoe Bay Unit and Point
Thompson Unit, BP sold 3.1% of its interest to Phillips in 2001.
-- BP now owns a 46.9% interest in TAPS, with the balance owned by five
other companies. Each of the TAPS participants uses its undivided
interest in TAPS as a common carrier, separately publishing tariffs
and receiving tenders for shipments through its share in the capacity
of TAPS, and paying its volumetric share of operating costs. At peak
throughput, the TAPS system carried around 2 mmb/d. In 2001, TAPS
transported production from Prudhoe Bay and the other North Slope
fields averaging 1 mmb/d. In October, TAPS was vandalized and
punctured by a bullet, resulting in a leak of 6,600 bbls of oil.
Following a shut-in of 62 hours for repair, during which 730,000
barrels (net) of production was lost , full operation was restored.
Clean-up operations continue into 2002. Security measures on the line
and at the North Slope fields were increased in September and remain
at a high level.
For a description of the procedures relating to the tariffs to be
charged to users of TAPS and a general description of pipeline
regulation, see Regulation of the Group's Business -- United States
within this item.
There are a number of unresolved protests with regard to the yearly
tariffs which are filed and which set out the charges for shipping oil
through TAPS. These items are in the process of resolution at the
Federal Energy Regulatory Commission (FERC) and the Regulatory
Commission of Alaska.
The use of US-built and US-flagged ships is required when transporting
Alaskan oil to markets in the USA. In accordance with this, BP America
Inc. has a chartered fleet of 10 US-flagged tankers to transport
Alaskan crude oil to markets. Over the next few years, we plan to
begin replacing our US-flagged fleet as existing ships, whose average
age is 23.3 years, are retired in accordance with the Oil Pollution
Act of 1990. For discussion of the Oil Pollution Act of 1990, see
Regulation of the Group's Business -- Environmental Protection. In
September 2000, BP contracted for the delivery of three 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 2003, 2004 and
2005. In 2001, BP exercised the first of three options for additional
vessels. This fourth tanker is scheduled for delivery in 2006.
-- The Forties Pipeline System in the UK (BP 100%) is an integrated oil
and natural gas liquids transportation and processing system that
handles production from over 40 fields in the central North Sea. The
system was upgraded in 1993 and has a capacity of more than 1 mmb/d.
During 2001, average throughput was approximately 783 mb/d, compared
with 804 mb/d in 2000.
-- BP operates and has a 29.5% interest in the Central Area Transmission
System (CATS), a 400-kilometre natural gas pipeline system in the
central UK sector of the North Sea. The pipeline has a transportation
capacity of 1.7 bcf/d. It carries both proprietary and other
companies' volumes to a natural gas terminal at Teesside, Northeast
England. CATS offers its customers the choice of natural gas
transportation services or transportation and processing via two 600
mmcf/d processing trains with the capability to deliver NGLs for
export or for local industry with natural gas entering the UK National
Transportation System. In 2001 CATS handled throughput of 1.6 bcf/d.
-- BP, as AIOC operator, manages and has a 34.1% interest in the Western
Export Route Pipeline between Sangachal, which is near Baku in
Azerbaijan, and Supsa on the Black Sea coast of Georgia. AIOC also
operates the Azeri leg of the Northern Export Route Pipeline between
Sangachal and Novorossiysk in Russia. The combined capacity of the
pipelines is in excess of 200 mb/d. Transit agreements were completed
with the governments of Azerbaijan, Georgia, and Turkey to support
implementation of a 1 mmb/d pipeline from Baku to Ceyhan via Tbilisi
on the Turkish Mediterranean coast. BP along with seven partners in
the consortium to promote development of the BTC pipeline have
completed a number of Host and Inter-Government Agreements in 2001,
including one for Georgia. Front-End Engineering Design has been
started. The additional export capacity provided is expected to be
largely taken by future production from ACG and other Azerbaijan
developments.
-- In October 2001 CPC (BP 5.75%) commissioned a 1,510 kilometre pipeline
from Kazakhstan to the Russian port of Novorossiysk. The pipeline has
an initial capacity of 28.2 million tonnes a year and will carry crude
from the Tengiz field (BP 2.3% through the Lukarco joint venture).
-- A joint study team, including BP and the other major North Slope
natural gas resource owners, is nearing completion of a major study
investigating a pipeline project to deliver Alaskan natural gas to
major North American markets. Key activities in 2002 will be to
mitigate the risks inherent in a project of this magnitude, including
working with legislative bodies to establish an appropriate regulatory
framework.
34
Liquefied Natural Gas
Within BP, the Exploration and Production business is responsible for the
supply of Liquefied Natural Gas (LNG) and BP's Gas and Power stream is
responsible for the subsequent marketing and distribution of LNG (see details
under 'Gas and Power -- International Gas and LNG').
-- BP has a 34% interest in the first train of the Atlantic LNG plant in
Trinidad and is the sole supplier of natural gas to this train, which
commenced operations in February 1999. In the fourth quarter of 2000,
government and partner approvals were obtained to expand Atlantic LNG
by an additional two trains. In 2001, construction of Train 2
progressed as planned, with first sales expected in the third quarter
of 2002. Gas for Train 2 will come from the Amherstia field (BP 100%
and operator) initially. To enable delivery of gas to Atlantic LNG's
planned Train 3, BP is constructing its biggest offshore gas
processing platform (Kapok) and its largest offshore pipeline
(Bombax). Construction is proceeding on schedule to meet the planned
start-up of Train 3 in 2003. Also in 2001, the Front-End Engineering
and Design for a fourth LNG train was started. BP is expected to
supply at least 34% of the natural gas requirements for this 4.8-mtpa
(millions of tonnes per annum) plant.
-- In Trinidad and Tobago, we announced our agreement to hold a 37% share
in the Atlas methanol plant, with Methanex, the Canadian operator,
holding the remainder. Atlas is expected to be the largest methanol
plant ever built and is intended to set new standards for cost,
efficiency and environmental emissions as a result of the use of
innovative leading edge technology. BP, through its customer NGC, will
supply 100% of the natural gas demand for the plant.
-- In Indonesia, the VICO (BP 50%) operations produced 1.21 bcf/d of the
natural gas supply to the LNG plant at Bontang; of this total, 236
mmcf/d is the BP net share. VICO, as well as operating the extensive
East Kalimantan pipeline network, is natural gas co-ordinator for all
of the 4 bcf/d natural gas feedstock to the Bontang facility and is
Technical Advisor to PT Badak, the LNG plant operating company.
Bontang, currently the world's largest LNG facility, consists of eight
LNG trains with a nominal total capacity of 22.6 mmtpa, with the
possibility of expanding to a ninth train being considered.
-- In addition, we operate the Wiriagar and Berau fields in Papua. These
should provide the largest share of natural gas feed to the Tangguh
LNG project which is expected to become the third LNG centre in
Indonesia, the world's largest LNG-producing country.
-- In early 2001, BP was selected as the leading foreign company (BP 30%
equity share) in China's first LNG re-gasification terminal project
near Shenzhen in Guangdong Province. Planned activities in 2002
include the completion of the feasibility study and the formation of
the joint venture company. The terminal is expected to start-up in
late 2005 and is planned initially to have a capacity of 3.2 mmtpa
with the ability to be expanded well beyond that.
-- In 2002, construction is expected to be completed on an $86 million
gas-to-liquids demonstration unit, located in Nikiski, Alaska. This
plant will utilize BP's compact reformer technology, enabling a
significant improvement in gas-to-liquids commercial competitiveness.
Plant start-up is scheduled for second quarter of 2002.
-- In Australia, our interest in the North West Shelf Venture (BP 16.7%)
saw BP's production increase 3.3% to 80.6 mboe/d in 2001. Growth was
gas-led by LNG (up 0.9 mboe/d) and domestic natural gas (up 1.6
mboe/d). Along with production growth, cost savings were a
considerable value driver yielding $25 million of additional earnings.
In April 2001, construction of LNG Train 4 was sanctioned. The Train,
scheduled to commence in June 2004, should increase North West Shelf
LNG capacity by approximately 50%. In December 2001, two Echo Yodel
condensate wells were commissioned, three months earlier than
initially planned.
-- We have a 10% equity shareholding in the Abu Dhabi Gas Liquefaction
Company (ADGAS), which in 2001 supplied 5.4 million tonnes of LNG, up
4% on 2000.
35
GAS AND POWER
The Gas and Power business was created to market our substantial natural
gas reserves and to develop a leading gas and power marketing and trading
business. Since its inception, we have been investing in both organizational
capability and capital assets to grow this new business segment.
The business is organized into three activities: natural gas marketing and
trading; international natural gas and liquefied natural gas (LNG); and power
activities. On January 1, 2001, the NGL business, located in North America, was
transferred to the Gas and Power business from Refining and Marketing and is
included in the marketing and trading activities. On January 1, 2002, the solar,
renewables and alternative fuels business activities were transferred to the Gas
and Power business from Other Businesses and Corporate. Also from that date the
segment has been renamed Gas, Power and Renewables.
Years ended December 31,
------------------------
2001 2000 1999
----- ----- -----
($ million)
Turnover ................................................ 39,208 21,013 8,073
Total replacement cost operating profit ................. 521 571 437
Total assets............................................. 5,313 6,605 2,831
Capital expenditure and acquisitions..................... 359 336 81
Marketing and trading activities within the stream are focused on the
relatively open and liberalized natural gas and power markets of North America,
the United Kingdom and certain parts of the Rest of Europe, although elements of
long-term natural gas contracting activity are also still included within the
Exploration and Production business segment. Our business is built on the
foundation of our major natural gas supply reserves being within or in close
proximity to these markets. As natural gas and power markets converge, our entry
into power marketing and trading is a logical extension of our natural gas
business. We market and trade BP and third-party natural gas and, to a much
lesser extent, power and related energy management services. Our NGL business, a
part of our North America marketing and trading activities, is engaged in the
processing, fractionation and marketing of ethane, propane, butanes and pentanes
extracted from natural gas.
International natural gas and LNG activities involve developing
opportunities to monetize our upstream natural gas resources, and as such, are
conducted in close collaboration with the Exploration and Production business.
Our international natural gas strategy is to capture a disproportionate share of
growth in the international demand for natural gas and is focused on growing
natural gas markets including the USA, Canada, Spain and many of the emerging
markets of the Asia Pacific region, notably China, where substantial demand
growth is expected. LNG activities are focused on the marketing and trading of
BP and third party LNG. There is close linkage between the LNG supply activities
in the upstream business and Gas and Power's LNG marketing and trading
activities.
In addition to power marketing and trading activities noted above, we are
involved in several gas-fired power generation projects. Our power strategy
focuses on projects that either monetize our equity natural gas and/or
cogeneration projects on Group sites that contribute additional value from the
reduction of Group power costs and/or enable excess power to be sold.
Marketing and Trading Activities
Our marketing and trading activities are concentrated in the markets of
North America and the United Kingdom. Gas sales volumes have increased from 14.5
bcf/d in 2000 to 18.8 bcf/d in 2001. Most of this growth was realized in North
America.
Years ended December 31,
------------------------
Gas sales volumes (a) 2001 2000 1999
----- ----- -----
(million cubic feet per day)
UK....................................................... 2,641 2,526 1,693
Rest of Europe........................................... 213 178 167
USA...................................................... 8,327 6,524 4,047
Rest of World............................................ 7,613 5,243 3,023
----- ----- -----
Total.................................................... 18,794 14,471 8,930
===== ===== =====
------------
(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.
36
North America
BP is the leading natural gas producer in North America, the world's
largest natural gas market. We are building our natural gas and power marketing
and trading business in North America upon this strong foundation. Our North
American total natural gas sales volumes have grown from 5.4 bcf/d in 1999 to
9.7 bcf/d in 2000 and to 13.4 bcf/d in 2001. Of these volumes, 4.1 bcf/d (2000
3.6 bcf/d) were supplied from BP upstream producing operations. The sales
volumes were a mixture of sales to commercial and industrial customers, sales to
trade counter parties and term sales.
Our North America natural gas marketing and trading strategy seeks to
maximize returns from building a distinctive network of connected assets,
customers and activities thereby optimizing our portfolio and supply chain
management and adding value through trading. These assets could be owned by BP
or contractually accessed through agreements with our customers or other third
parties. The extension of this network of assets is the principal purpose of our
capital expenditure programme in North America for our marketing and trading
activities.
Years ended December 31,
------------------------
NGL sales volumes 2001 2000 1999
----- ----- -----
(thousand barrels per day)
UK....................................................... -- -- --
Rest of Europe........................................... -- -- --
USA...................................................... 221 154 115
Rest of World............................................ 189 195 192
----- ----- -----
Total.................................................... 410 349 307
===== ===== =====
The transfer of the North American NGL business to Gas and Power in 2001
recognizes that NGLs are an integral part of the overall natural gas value chain
and will also take advantage of our natural gas marketing and trading skill base
in North America. The majority of BP's NGLs are marketed on a wholesale basis
under annual supply contracts that provide for price redetermination based on
prevailing market prices. 2001 sales volumes of NGL averaged 410 mb/d (2000 349
mb/d). 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 five fractionator plants in
Canada and the United States. Two of these are located in Canada in Fort
Saskatchewan, Alberta and Sarnia, Ontario, and three are located in the United
States in Hobbs, New Mexico, Baton Rouge, Louisiana and Mont Belvieu, Texas.
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 the largest producer of natural gas in the UK. Total natural gas
sales in the UK were 2.5 bcf/d in 2001, 2.5 bcf/d in 2000 and 1.7 bcf/d in 1999.
Of these volumes 1.7 bcf/d (2000 1.7 bcf/d and 1999 1.3 bcf/d) were supplied
from our 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 trade physical
natural gas on the UK spot market.
From October 1, 2001 we have agreed to purchase 56 bcf of natural gas per
annum for 15 years from Statoil, a Norwegian oil and natural gas producer. This
is the first significant contract for natural gas supplies to the UK from the
Norwegian continental shelf since the Frigg contract in 1977.
We have a 10% interest in the Interconnector, a 1.9-bcf/d, 240-kilometre,
40-inch sub-sea natural gas pipeline between Bacton in the UK and Zeebrugge in
Belgium, which effectively links the natural gas markets of the UK and
Continental Europe.
Rest of Europe
We are continuing to build a natural gas and power marketing and trading
business in northern and southern Europe. Our interest in the European market is
driven by the size and growth potential of the market, deregulation and the
proximity of BP natural gas supplies.
In northern Europe, we have established marketing activities in the
Netherlands, Belgium, France and Germany. In March 2001, we acquired a 51%
interest in Pmax Portfolio Management GmbH (Pmax), based in Hamburg, Germany.
Pmax is an electricity marketing company, which markets electricity to medium
and large customers in Germany. This investment has enabled the growth of our
energy marketing business in Germany and extends our energy services and trading
opportunities within northern Europe.
37
As part of the Veba deal, we announced the proposed divestment of our 25.5%
interest in Ruhrgas. This sale has since been prohibited by Germany's Federal
Cartel Office although the decision is being appealed to the German Economics
Ministry, which is expected to rule in mid-2002.
In southern Europe we maintained our focus on Spain and Italy. The Spanish
natural gas market has continued to grow and it is liberalizing largely ahead of
the rest of continental Europe. We built on our position of being the first
foreign company to secure a licence permitting us to market natural gas to
industrial consumers outside the former monopoly, by growing the business to
maintain some 7% of the eligible industrial market by the end of 2001. To
achieve our growth, BP emerged with the maximum 25% share allowed from the
Release Gas programme run by the Spanish authorities (this was the programme
which required the incumbent Spanish natural gas supplier, Gas Natural, to
release 150 bcf of natural gas to new entrants over a 2 year period from
December 2001) and we added a major LNG supply contract from a Middle Eastern
supplier backed by leasing an LNG carrier. We used the power commercializer
license we were awarded in December 2000 to market power to a set of test
industrial consumers in Spain's liberalized power market. Italy continues to be
a significant and growing natural gas and power market (the second largest in
Continental Europe) which is liberalizing and presenting opportunities to us.
International Gas and LNG
Our international natural gas and LNG activities are focused on developing
worldwide opportunities to capture international natural gas growth and to
monetize our upstream natural gas resources.
Construction is underway on the Bahia de Bizkaia project in Bilbao, Spain,
an integrated 97.1 billion cubic feet per annum LNG import/regasification and
800 megawatt combined cycle, gas-fired power generation facility. BP has a 25%
equity share in the facility and BP equity natural gas from Trinidad and Tobago
will supply the facility. After regasification of the LNG, approximately 40% of
the natural gas will feed the power plant, while the remaining natural gas will
be fed into the local natural gas distribution system.
China is another area of activity. Currently, natural gas meets only two
percent of China's energy needs, but this is expected to increase significantly.
BP announced in March 2000 that it had plans to form a natural gas marketing
joint venture with PetroChina aimed at supplying the growing energy markets of
eastern China. Longer term, the alliance allows BP to be involved in marketing
natural gas from East Siberia where BP has an interest in the substantial
undeveloped Kovyktinskoye field. In 2001, BP was selected as the foreign partner
in the joint venture tasked to develop the Guangdong project, China's first LNG
import terminal near the city of Shezhen. Phase 1 of the project will have a
capacity of 3 million tonnes a year and an associated 300 kilometres of pipeline
to link the terminal to the region. Guangdong is due on stream in 2006.
In a major step forward for the Pertamina and BP operated Tangguh LNG
Project in eastern Indonesia, Pertamina signed a Letter of Intent (LOI) in
November 2001 for delivery of LNG to GNPower of the Philippines. The LOI
provides for an exclusive period for Pertamina and GNPower to negotiate the
supply of LNG from Tangguh field.
The development of the LNG business requires the development of appropriate
LNG shipping capacity. During 2000, BP ordered two LNG tankers from Samsung
Heavy Industries for delivery in 2002 and 2003, together with options for a
further three ships. The first of these options was exercised in the first
quarter of 2001 for delivery in 2003.
As described under the heading Exploration and Production -- Midstream
activities -- Liquefied Natural Gas, our major LNG supplies are from Trinidad
and Tobago, VICO in Indonesia, ADGAS in Abu Dhabi and the North West Shelf in
Australia.
Power Activities
This business sector primarily participates in (i) power projects that
support monetization of our equity natural gas and (ii) cogeneration projects on
advantaged BP sites e.g., refining and chemical manufacturing sites. In addition
to power marketing and trading discussed above, we are also involved in three
power generation construction projects, including the Bahia de Bizkaia project
covered above.
38
Following the announcement of power development plans at BP's largest
refining and petrochemical complex, located in Texas City, Texas, construction
work at the site began in 2001 for the development of a 570-megawatt (MW)
cogeneration plant as a 50:50 joint venture with Cinergy Solutions, Inc. This
project is expected to provide low-cost steam, power and process heat to our
refining and chemicals businesses. The project is further expected to provide
improved generation efficiency, reduced power costs and reduced nitrogen oxide
emissions at the site. BP will supply natural gas to the plant and its excess
generation capacity will be used to support power marketing and trading
activities.
In December 2000, our 400 MW gas-fired power plant project at Great
Yarmouth in the UK entered its commissioning phase. Commissioning has been
delayed throughout 2001 due to technical problems. Work is underway with the
view to making it fully operational during 2002. We plan to operate this project
as a merchant plant, i.e. a power plant that sells electric power to 'spot'
customers, and BP is expected to provide natural gas to the plant.
39
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 its products in over 100
countries. It operates primarily in Europe and North America, but also markets
its products across South America, Australasia and in parts of South East Asia
and Africa.
Years ended December 31,
------------------------
2001 2000 1999
----- ----- -----
($ million)
Turnover (a)............................................. 120,233 107,883 60,143
Total replacement cost operating profit.................. 3,625 3,523 1,614
Total assets............................................. 43,102 45,785 26,099
Capital expenditure and acquisitions..................... 2,415 8,693 1,571
($ per barrel)
Global Indicator Refining Margin (b)..................... 4.06 4.22 1.24
----------
(a) Excludes BP's share of joint venture turnover of $403 million in 2001,
$13,112 million in 2000 and $17,117 million in 1999.
(b) The Global Indicator Refining Margin (GIM) is the average of seven regional
indicator margins weighted for BP's crude refining capacity in each region.
Each regional indicator margin is based on a single representative crude
with product yields characteristic of the typical level of upgrading
complexity.
There are four key components of the Refining and Marketing stream each
with its own focus and strengths. In refining, the focus is on top-quartile
performance; to measure this we primarily use the regional refining surveys by
Solomon Associates to assess our competitive position against benchmarked
industry measures such as costs per barrel. In retail, the focus is on
high-growth geographical areas and customer segments through the
convenience-store market. In lubricants, the focus is on capitalizing on the
leading Castrol and BP brands, potentially giving increased growth in both
margin and volume. Finally, with respect to the stream's commercial and
industrial activities, such as aviation, we focus on attractive customer
segments to capture margin and growth.
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 and marketers of gasoline and
hydrocarbon products in the USA. We have extensive retail and commercial
businesses in the UK, the Rest of Europe, Australasia, Africa and South East
Asia. Worldwide, BP continues to be a leading marketer of fuels, served by a
refining network with key refineries among the top performers in their regions.
The merger of BP and Amoco on December 31, 1998 and the acquisitions of
ARCO, Burmah Castrol and ExxonMobil's interest in the fuels business of the
BP/Mobil European joint venture in 2000 substantially strengthened our position
in refining and marketing in the USA, UK, and Western Europe.
With effect from February 1, 2002, BP acquired Veba Oil's retail and
refining assets in Germany and Central Europe. The Veba acquisition makes BP the
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. Veba has interests in five high quality clean
fuels refineries in Germany.
In 2001, BP completed the integration of Burmah Castrol, sold its Mandan,
North Dakota, and Salt Lake City, Utah refineries and restructured its
commercial business in Northern Europe. Growth in the number of employees in
other areas was more than offset by these activities with employee numbers
decreasing from 67,000 at the start of the year to 64,600 at the year end.
40
Refining
In refining, our key objective is to safely operate an advantaged refining
system more profitably than those of our competitors. For BP, advantaged
characteristics relate to supply - the refinery's position in relation to the
market; clean fuels - how the refinery supports our clean fuels strategy; and
integration value - how the refinery adds value by virtue of integration with
other parts of the Group's business. Refining's focus remains continued safe,
reliable, and efficient operations, income growth, and increased supply of
cleaner burning transport fuels for BP's Clean Cities programme.
In line with the Company's global refining strategy, to retain only those
refineries that either provide advantaged supplies for its marketing operations,
or are integrated with other parts of the business, BP completed the sale of its
Salt Lake City, Utah, and Mandan, North Dakota refineries to Tesoro, on
September 6, 2001. BP has reached agreement with Giant Industries, Inc. for
Giant to acquire BP's wholly owned Yorktown, Virginia refinery; the sale is
anticipated to close in the second quarter of 2002. BP has also announced the
intention to sell its 33% equity interest in the Singapore Refining Company
(SRC).
In the US, BP owns and operates five large modern fuels refineries with
extensive clean fuel capability consistent with our strategy. These are located
in Texas City, Texas; Whiting, Indiana; Toledo, Ohio; Carson City, California;
and Cherry Point, Washington.
In Europe, BP operates seven fuels refineries. These are Bayernoil in
Germany, Castellon in Spain, Coryton and Grangemouth in the UK, Lavera in
France, Mersin in Turkey, and Nerefco in the Netherlands. All are wholly owned
by BP except Bayernoil, Mersin, and Nerefco, where BP's equity interests are
55%, 68%, and 69%, respectively. Additionally, BP has a 17% equity interest in
the Reichstett refinery in France, and wholly owns the Hamburg, Germany
lubricants refinery. BP has announced a major restructuring project at the
Grangemouth refinery in 2002 to increase the long-term competitiveness of the
refinery and chemical complex.
In the rest of the world BP operates three principal refineries. These are
located at Bulwer Island, Australia, Kwinana, Australia, and Singapore. Both
Australian refineries are wholly owned by BP.
BP also has a 50% interest in the Durban, South Africa refinery, a 24%
interest in the Whangarei, New Zealand refinery, and a 13% equity interest in
the Mombasa, Kenya refinery.
With effect from February 1, 2002 BP acquired a 51% stake in Veba Oil. Veba
Oil owns the Lingen refinery and has interests in four other refineries -
Gelsenkirchen (50%), Schwedt (18.75%), Miro (12%), and Bayernoil (12.5%). These
interests are held through Ruhr Oil, a 50/50 joint venture with Petroleos de
Venezuela SA (PdVSA). Veba's total net refining capacity amounts to roughly
310,000 barrels per day. Besides adding refining capacity in advantaged
geographic areas, we believe that the addition of these plants will
significantly enhance BP's clean fuels capability within Central Europe.
41
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 summarised.
Years ended December 31,
------------------------
Refinery throughputs 2001 2000 1999
----- ----- -----
(thousand barrels per day)
UK (a)................................................... 364 324 271
Rest of Europe (a)....................................... 663 602 540
USA...................................................... 1,526 1,625 1,340
Rest of World............................................ 376 365 371
----- ----- -----
2,929 2,916 2,522
For BP by others......................................... 14 12 19
----- ----- -----
Total.................................................... 2,943 2,928 2,541
===== ===== =====
Refinery capacity utilization
Crude distillation capacity at December 31, (a) (b)...... 3,259 3,203 2,801
Crude distillation capacity utilization (c).............. 94% 95% 95%
USA.................................................... 95% 97% 95%
Europe................................................. 94% 96% 94%
Rest of World.......................................... 93% 87% 96%
----------
(a) Includes the BP share of the BP/Mobil joint venture until August 1, 2000.
(b) The crude distillation capacity figures are based on gross rated capacity,
which assumes no loss of capacity due to shutdowns. The figures for 2001
reflect the sale of the Salt Lake City, Utah and Mandan, North Dakota
refineries. The figures for 2000 reflect the unwinding of the BP/Mobil
European joint venture, the Alliance, Louisiana refinery sale, and the
acquisition of ARCO's two west coast fuels refineries: Carson City,
California and Cherry Point, Washington.
(c) Crude distillation capacity utilization is defined as the percentage
utilization of capacity per calendar day over the year after making
allowances for average annual shutdowns at BP refineries (i.e. net rated
capacity).
Marketing
Marketing comprises three business areas: Retail, Commercial and
Industrial, and Lubricants. We market a comprehensive range of refined oil
products worldwide. These products include gasoline, gasoil, marine and aviation
fuels, heating fuels, LPG, lubricants and bitumen.
The following table sets out refined product sales by area. A significant
increase in sales was achieved in 2001 as a result of the full year impact of
the acquisition in 2000 of ARCO, Burmah Castrol and ExxonMobil's interests in
the BP/Mobil European fuels business.
42
Years ended December 31,
------------------------
Sales of refined products (a) 2001 2000 1999
----- ----- -----
(thousand barrels per day)
Marketing sales:
UK (b)(c).............................................. 266 256 235
Rest of Europe (b)..................................... 1,062 901 794
USA.................................................... 1,866 1,783 1,427
Rest of World.......................................... 603 480 423
----- ----- -----
Total marketing sales (d)................................ 3,797 3,420 2,879
Trading/supply sales (d)................................. 2,409 2,103 1,816
----- ----- -----
Total refined products................................... 6,206 5,523 4,695
===== ===== =====
($ million)
Proceeds from sale of refined products (b)............... 82,241 74,239 41,497
----------
(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 2001 2000 1999
----- ----- -----
(thousand barrels per day)
Aviation fuel............................................ 515 474 366
Gasolines................................................ 1,659 1,512 1,298
Middle distillates....................................... 1,077 945 765
Fuel oil................................................. 351 338 319
Other products........................................... 195 151 131
----- ----- -----
Total marketing sales ................................... 3,797 3,420 2,879
===== ===== =====
In marketing our aim is to grow our customer base, both in existing and new
markets - in terms of attracting new customers and by covering a wider
geographic area. We are aiming at increasing our revenue per customer by
attracting retail customers to spend more in convenience stores and business
customers to spend more on value-added services and solutions.
Our objective is to create a more capital-efficient, higher-return business
by differentiating where we choose to invest directly from where we seek to
invest through partners. In addition we recognize that our customers are
demanding a wider choice of fuels, particularly fuels that are cleaner and more
efficient. Through our integrated refining and marketing operations we believe
we are able to meet these customer needs.
During 2001 we continued implementation of our clean fuels initiative with
BP marketing cleaner fuels in 113 cities at December 31, 2001.
Retail
In retail, we differentiate between two distinct segments: a fuels segment
in which we only 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. We plan to concentrate our investment primarily in developing
additional store space on existing real estate in our core metropolitan markets.
43
Years ended December 31,
------------------------
Shop sales (a) 2001 2000 1999
----- ----- -----
($million)
UK....................................................... 458 357 265
Rest of Europe........................................... 904 663 569
USA...................................................... 1,510 1,251 542
Rest of World............................................ 362 353 365
----- ----- -----
Total.................................................... 3,234 2,624 1,741
===== ===== =====
Direct-- managed......................................... 1,650 1,397 994
Franchise................................................ 1,504 1,154 707
Shop alliances........................................... 80 73 40
----- ----- -----
Total.................................................... 3,234 2,624 1,741
===== ===== =====
(a) Shop sales reported are sales through direct-managed stations, franchisees
and the BP share of shop alliances. Sales figures exclude sales taxes and
lottery sales but include quick service restaurant sales. The sales include
the BP share of the relevant sales within the BP/Mobil European joint
venture until August 1, 2000.
Our retail network is concentrated in Europe and the USA, with established
operations in Australasia and Southern Africa as well. We are developing
networks in China, Poland and Russia.
In 2001, we opened 335 new BP Connect sites primarily in the UK and US as
part of our retail strategy that builds on our advantaged locations, strong
market positions and brand. These new BP Connects include new sites, razed and
rebuilt sites, and extensive upgrading and remodeling of some existing stations.
The BP Connect sites offer our customers cleaner fuels, a wider range of
services and a distinctive food offer. In addition, over 4,600 stations
worldwide were reimaged to the new BP Helios.
At the same time as we are rolling out the new convenience offer, we
continue to improve the efficiency of our retail network by reducing operating
costs through a process of regularly reviewing the network. Actions taken during
2001 have included divesting sites and networks, principally in those markets
where our growth will be focused on a fuels only offer delivered through dealers
and jobbers. Alongside this activity, we have continued to upgrade existing
sites and invest in new sites, principally in markets where we believe there is
growing demand for our full convenience offer.
At December 31, 2001, there were approximately 26,800 BP, Amoco and ARCO
branded service stations worldwide, some 2,200 less than at the end of 2000. The
Veba Oil acquisition will add approximately 3,000 Aral-branded stations in
Central Europe prior to regulatory required divestments. Subsequent to the
integration of the Aral-branded stations the worldwide number of stations is
expected to decline over the next few years as we continue to optimize the
efficiency of our retail network.
At December 31, 2001, BP's retail network in the USA comprised about 15,500
service stations of which approximately 10,600 were jobber owned. Developments
in the USA during 2001 included the divestment of about 500 service stations in
line with the strategy to concentrate ownership of real estate in markets
designated for development of the convenience offer and stations and jobbers
previously supplied from BP's Mandan, North Dakota and Salt Lake City, Utah
refineries. In the US, we opened 196 BP connect sites and reimaged 1,525
stations to the new BP Helios.
In the UK and the Rest of Europe, BP's network comprised about 7,500
service stations at December 31, 2001. We opened 80 BP Connects in Europe with
the majority being in the metropolitan London area and reimaged throughout
Europe approximately 3,000 stations to the new BP Helios image. 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
2,500 stations in Germany and 155 stations in Austria. In Central Europe, Aral
has over 130 stations in the Czech Republic, Slovakia and Hungary. The
combination of the BP and Aral network in Poland makes BP the largest foreign
oil company in Poland with over 270 stations. In Russia, we continued to expand
our retail network by adding seven stations in 2001 bringing our total number of
stations in the Moscow metropolitan area to 34 at December 31, 2001.
44
At December 31, 2001 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 alliance with Petrochina in
Guangdong Province in the coastal region of China had 201 stations at December
31, 2001, 105 of which BP reports as its share of the joint venture. 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 2002. In
addition, BP has 112 stations in Venezuela and 15 stations in Mexico. BP has
agreed to sell its 21 service stations in Japan to Japan Energy with the sale
expected to be completed in the first half of 2002. BP's exit from retail
marketing in Japan is not expected to have any impact on its other business
activities there.
Commercial and Industrial
In our Commercial and Industrial business we aim to attract more customers
through innovation in multi-product offers and cleaner fuels, packaged with a
range of value-added services and solutions, thus aiming to increase customer
spend and growth in volumes at above the rate of market growth. For example, our
offer to Commercial and Industrial customers has expanded to include BP's
flexible pricing mechanism complete with a range of clean fuels and energy
saving lubricants. Our Commercial and Industrial business operates in
Australasia, Europe, Southern Africa and the USA. In 2001, BP restructured its
small volume domestic and commercial fuels business exiting some markets and
consolidating operations in other markets.
Our aviation business sells jet and other aviation fuels to airlines and
general aviation customers as well as providing technical services to airlines
and airports. During the last few years, 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. The effect of the events of September 11,
2001 has been a reduction in aviation sales volumes.
Lubricants
We manufacture and market lubricant products and also supply related
products and services to business customers and end-consumers in over 60
countries directly, and to the rest of the world through local distributors. Our
business is concentrated on the higher value sectors of automotive lubricants,
especially in the consumer sector, but also has a strong presence in commercial
sectors such as marine and specialized industrial segments.
BP markets through its two major brands, Castrol and BP, and several
secondary brands including Duckhams and Veedol. The Veba acquisition will
increase our lubricants position in Central Europe as the Aral brand is
integrated into the BP Lubricants organization.
Our lubricants business is organized by market segment. The main
characteristics of each part of the business are as follows:
Consumer markets: We supply lubricants, other products and related business
services to intermediate customers (for example retailers, workshops) who in
turn serve end-consumers (car, motorcycle, leisure craft owners) in the mature
markets of Europe and North America and also in the fast growing markets of the
developing world (Asia, India, Middle East, South America and Africa). The
Castrol brand is recognized worldwide and we believe it provides us with a
significant competitive advantage.
Commercial vehicle and general industrial markets: We supply lubricants and
lubricant related services to automotive manufacturers and other industrial
customers.
Marine market: We supply lubricants and fuels, on a global basis, to major
shipping companies as well as to small fishing vessel operators. We are the
leading global participant in the marine lubricants market and operate a network
of offices and supply points in more than 900 ports across 90 countries. During
2000, we formed an innovative global strategic partnership 'Marine Alliance'
with Unitor, a major supplier of marine consumables, to supply a full range of
products and services to marine customers. This partnership is targeting market
growth through supplying an expanded range of products and services.
Specialist industrial market: We supply metalworking fluids and lubricants
alongside a range of business services, such as fluid management, to the metal
component manufacturing sector. We also have a significant high performance
industrial lubricants business in some key markets.
45
Supply and Trading
We are one of the world's major traders of crude oil and refined products,
dealing extensively in physical and futures markets. Our portfolio of purchases
and sales is spread among spot, term, exchange and other arrangements, and
covers a range of sources and customers to match the location and quality
requirements of the Group's refineries and the various markets, while seeking to
ensure flexibility and cost-competitiveness. In addition, the Group's
oil-trading division undertakes trading in physical and paper markets in order
to contribute to the Group's income.
Transportation
Our Refining and Marketing business owns, operates or has an interest in
extensive transportation facilities for crude oil, refined products and
petrochemical feedstocks in the US. It also has interests in a number of crude
oil and product pipelines in the UK and the Rest of Europe.
We transport crude oil to our refineries principally by ship and through
pipelines from our import terminals. We have interests in seven major crude oil
pipelines in the UK and the Rest of Europe and sixteen in the USA.
Bulk products are transported between refineries and storage terminals by
pipeline, ship, barge, and rail. Onward delivery to customers is primarily by
road. We have interests in nine major product pipelines in the UK and the Rest
of Europe and six in the USA.
During 2001 BP sold several transportation assets directly connected with
BP refineries that had been divested including the products pipelines associated
with the Alliance, Louisiana refinery, the products and crude lines associated
with the Mandan, North Dakota refinery, and BP's 43.75% interest in the Frontier
Pipeline crude oil pipeline associated with the Salt Lake City, Utah refinery.
BP also sold its 26.5% interest in the Pacific Pipeline in June 2001, and
in March 2002 sold its interests in three Rocky Mountain pipelines.
Shipping
BP Shipping owns or operates an international fleet of crude and product
tankers and LNG carriers carrying cargoes for the Group and for third parties.
It also offers a wide range of services to Group and third party marine
customers.
At December 31, 2001 the Group controlled or operated an international
fleet of five Product Carriers, totalling approximately 0.19 million deadweight
tons (dwt). Excluding BP companies in the USA, the Group had fourteen crude oil
tankers (six Very Large Crude Carriers (VLCCs), and eight Medium Crude Carriers)
totaling approximately 2.88 million dwt.
It also had an interest in six LNG carriers which are dedicated to
transportation of Australian North West Shelf natural gas.
BP Companies in the USA had 19 tankers (ten Large Crude Carriers, four
Medium Crude Carriers and five Product Carriers), totalling approximately 1.84
million dwt on long-term charter. BP owns four barges totalling 0.1 million dwt
and has four vessels under construction totalling 0.64 million dwt.
In addition, a large number of small vessels are used by Group companies
around the world.
46
CHEMICALS
Our Chemicals business is a major producer of petrochemicals 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. Chemicals is also responsible for the supply, marketing and
distribution of chemical products to bulk, wholesale and retail customers.
Years ended December 31,
------------------------
2001 2000 1999
----- ----- -----
($ million)
Turnover (a)............................................. 11,515 11,247 9,392
Total replacement cost operating profit ................. 128 760 686
Total assets............................................. 15,098 13,674 13,021
Capital expenditure and acquisitions..................... 1,926 1,585 1,215
($/tonne)
Chemicals Indicator Margin (b)........................... 108(c) 126 (d) 114
----------
(a) Excludes BP's share of joint venture turnover of $102 million in 2001, $67
million in 2000, and nil in 1999.
(b) The Chemicals Indicator Margin (CIM) is a weighted average of externally
based product margins. It is based on market data collected by Chem Systems
in their quarterly market analyses, then weighted based on BP's product
portfolio. While it does not cover our entire portfolio, it includes a
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, acetic acid, vinyl acetate monomers and nitriles. Not
included are fabrics and fibers, plastic fabrications, poly-alpha olefins,
anhydrides, engineering polymers and carbon fibres, speciality
intermediates, and the remaining parts of the solvents and acetyls
businesses.
(c) Provisional. The data for the current year is based on eleven months of
actual data and one month of provisional data.
(d) Restated following review of product margins with Chem Systems.
Chemicals margins are subject to industry cyclicality. The external drivers
of our results in 2001 were determined by market demand levels, new industry
supply starting up, pressures on feedstock prices, portfolio restructuring and
business combination activity. In 2002, the chemical industry's external
environment is expected to continue to see margins under pressure.
Our strategy is to create competitive advantage in petrochemicals through
adding value to Group hydrocarbons, industry cost leadership, world-leading
technology, strong market positions, and a bias to high growth products.
The Chemicals portfolio comprises three main sectors:
Aromatics and Derivatives. This sector comprises the production and
conversion of Aromatics (Xylenes) into Purified Isophthalic Acid (PIA) and
Purified Terephthalic Acid (PTA). PIA and PTA are chemical intermediates that
are used in the production of fibres, containers, films and coatings.
Olefins and Polymers. The Olefins sector covers the production of the basic
building blocks of chemical intermediates, such as ethylene and propylene. These
are used in our polymers businesses to produce a wide range of polymers for
commonly used products such as packaging, coatings, lubricants and detergents.
Intermediates. This business sector adds value to raw materials produced by
our other chemicals activities and includes acetic acid and other derivatives.
Intermediates are used by the automotive, construction, engineering
plastics and resins, consumer goods and packaging industries.
Management of the portfolio is underpinned by five strategic tenets:
Adding value to BP Group hydrocarbons. As the petrochemicals arm of an oil
major, we believe this is a key element of our competitive advantage, notably by
allowing us to combine feedstock, refining and chemical processing across large
integrated sites/systems.
47
Industry cost leadership. Continuing competitive pressures in the chemicals
industry require an enduring focus on cost reduction and we have made cost
management an important ongoing part of our business. We plan to continue to
reduce underlying costs in 2002 through a number of targeted actions, such as
achieving lower unit cost procurement, higher efficiency in our conversion
processes and utilizing new technology applications. We also intend to continue
to manage costs structurally by focusing our investment on a limited number of
world-class manufacturing sites. By limiting the number of sites, we benefit
from increased economies of scale and integration of chemical operations along
the various value chains associated with our portfolio.
World leading technology. We believe technology will continue to
distinguish the most successful companies from their competitors. Leading
technology makes us a preferred supplier and a preferred joint venture partner.
We intend to maintain and extend our leadership in the fundamental technologies
that underpin our core businesses. BP already has a number of leading
technologies in operation and is currently investing in production capacity,
utilizing recent breakthroughs in butanediol, vinyl acetate monomer and ethyl
acetate manufacture.
Strong market positions. This can be measured in a number of ways, such as
market share, growth potential or performance in terms of returns. We have
global leadership in paraxylene (PX), PTA, acetic acid, acrylonitrile,
trimellitic anhydride (TMA) and a number of other products. We have also
instituted a programme of marketing initiatives to improve our commercial
capability. The programme includes developments in e-commerce, including the
introduction of web-based marketing channels.
Bias to higher growth products. The majority of the BP portfolio is in
market sectors that have historically grown more rapidly than the industry
average.
We will therefore continue to focus our portfolio by investing in areas
offering a good fit and divesting where there is insufficient alignment with the
strategic tenets described above.
During 2001, we implemented or announced a number of structural changes
that should significantly strengthen our position as the petrochemicals arm of
an integrated energy company. The most significant structural changes were as
follows:
-- In May 2001 we acquired from Bayer the 50% of Erdoelchemie we did not
already own.
-- In November 2001 we finalized a transaction with Solvay, aimed at
strengthening our polymers businesses in both Europe and the United
States. Solvay has transferred its US and European polypropylene
businesses to BP. The two companies have combined their European and
US high-density polyethylene (HDPE) businesses to form BP Solvay
Polyethylene Europe (BP share 50%) and BP Solvay Polyethylene North
America (BP share 49%), respectively. In addition, BP has transferred
its engineering polymers business to Solvay.
-- In February 2002 BP acquired a majority stake in Veba Oil, based in
Germany. Veba's petrochemicals business, based at Gelsenkirchen and
Munchmunster, with net ethylene capacity of 0.7 million tonnes per
year, will help meet BP's future chemical feedstock needs in the
region.
We intend to divest the Fabrications, Fabrics and Fibers, and Burmah
Castrol Chemicals businesses when the external environment is favourable as
these businesses do not satisfy the five strategic tenets described above.
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 (2,851
kilotonnes per annum (ktepa)) and Hull (1,615 ktepa) in the UK; Lavera (1,825
ktepa) in France; Marl (628 ktepa) and Koln (4,276 ktepa) in Germany; Geel
(2,075 ktepa) in Belgium; and Texas City, Texas (2,654 ktepa), Chocolate Bayou,
Texas (3,285 ktepa), Decatur, Alabama (2,176 ktepa), and Cooper River, South
Carolina (1,332 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 about 3,000
ktepa as follows: Indonesia (550 ktepa), Korea (828 ktepa), Malaysia (1,291
ktepa), Taiwan (663 ktepa), China (107 ktepa), Philippines (60 ktepa) and Japan
(43 ktepa).
48
Years ended December 31,
------------------------
Production by region (a) 2001 2000 1999
----- ----- -----
(thousand tonnes)
UK....................................................... 3,125 3,137 3,737
Rest of Europe........................................... 7,925 6,713 5,993
USA...................................................... 8,943 9,874 9,917
Rest of World............................................ 2,723 2,341 2,206
------ ------ ------
Total production......................................... 22,716 22,065 21,853
====== ====== ======
----------
(a) Includes BP share of joint ventures, associated undertakings and other
interests in production.
The following table shows BP production capacity by major products and by
product group at December 31,2001.
Intermediates
Aromatics Olefins and
and Derivatives and Polymers Fabrications Total
--------------- ------------ ------------- ------
(thousand tonnes per annum)
Purified terephthalic acid............. 5,594 -- -- 5,594
Ethylene............................... -- 4,004 -- 4,004
Paraxylene............................. 2,702 -- -- 2,702
Polypropylene.......................... -- 3,091 -- 3,091
Styrenics.............................. -- 1,538 -- 1,538
Polyethylene........................... -- 2,483 -- 2,483
Acetic acid/anhydride.................. -- -- 2,260 2,260
Linear/poly alpha-olefins.............. -- -- 1,280 1,280
Acrylonitrile.......................... -- -- 949 949
Other ................................. 151 3,281 4,534 7,966
------ ------ ------ ------
Total production capacity (a) 8,447 14,397 9,023 31,867
====== ====== ====== ======
------------
(a) Includes BP share of joint ventures, associated undertakings and other
interests in production.
The production capacity increase from 2000 of approximately 5,000 ktepa
resulted from our acquisition of the 50% share of Erdoelchemie, the Solvay
transaction and organic growth from new plants and de-bottlenecking.
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.
Aromatics and Derivatives
The leading market positions of our key products give us access to a wide
range of high-quality options, in terms of both investments and growth. We
strive to be number one or two in terms of market share in the markets in which
we compete, and we are currently a global leader in PTA and PX. Our strategy has
been to bias our portfolio towards products that have been growing at a rate of
approximately 8-10% per year. This is approximately three times the rate of
global economic growth and compares with an estimated average of 4% for the
petrochemicals industry as a whole.
Products
PTA is important as a raw material for the manufacture of polyester; PIA is
used for isopolyester resins and gel coats; napthalene dicarboxylate (NDC) is
used for photographic film and specialized packaging.
BP is the world's largest producer of PTA, with an interest in
approximately 21% of the world's PTA capacity. PTA is manufactured at Cooper
River, South Carolina and Decatur, Alabama, in the USA, Geel in Belgium, and
Kuantan in Malaysia. We also produce PTA through Samsung Petrochemical Company
(SPC) in Korea (BP 35%), China America Petrochemical Company (CAPCO) in Taiwan
(BP 50%), PT Ami in Indonesia (BP 50%), Rhodiaco in Brazil (BP 49%) and TEMEX in
Mexico (BP 8.55%). The site in Taiwan is the largest PTA production site in the
world, followed by our Cooper River site, which is the second largest. These
two, together with the Korean and Decatur sites, represent four of the five
largest PTA production sites in the world.
49
PIA is produced in Joliet, Illinois; Geel, Belgium; and by the AGIC joint
venture (BP 50%) with Mitsubishi Gas Chemical Company in Japan. NDC is produced
at our plant in Decatur, Alabama.
BP is one of the world's largest producers of PX and metaxylene (MX), the
feedstocks for PTA and PIA, respectively. PX and MX are produced from mixed
xylene streams acquired from BP refineries and third party producers. The
Aromatics and Derivatives business is largely integrated, using our manufactured
PX as feedstock for the production of our PTA product.
Major Activities
-- Two new PTA plants are under construction in China and Taiwan, which
will use BP's new PTA technology. The Zhuhai (BP 85%) unit in China
should add 350-ktepa capacity. A new plant at our CAPCO joint venture
in Taiwan (BP 50%) should add a further 700-ktepa capacity. The new
Zhuhai and CAPCO units are both expected to commence operation in
2003.
-- Advanced manufacturing technology projects were completed at Texas
City and Decatur during 2001. These initial projects are part of a
broader plan to implement the introduction of leading edge process
technology and control systems.
-- The de-bottlenecking of the PTA No. 3 unit at Geel was successfully
completed, increasing capacity by 100 ktepa to 600 ktepa. This project
had demonstrated the ability to stretch our in-house technology.
-- Options were developed for site and technology for the next European
PTA investment (PTA No. 4). This is intended to be a world-scale
development sited in northwestern Europe to take account of
integration with customers and feedstock.
-- Joint efforts with Downstream resulted in a project to source PX
feedstock from BP Group refineries. This project has the two aims of
enabling northwestern European refineries to meet the increasingly
strict gasoline aromatic content regulations and bringing feedstock
supply for PX in house.
-- BP, in collaboration with several industry partners, has developed a
polyethylene terephthalate (PET) beer bottle that is believed to be
technically best in class and cost competitive with glass. Market
evaluation and roll out is expected to occur in the first half of
2002. The vision is to establish PET as a competitive third packaging
material in the global beer market, developing substantial new markets
for BP's polyester intermediate product lines.
Olefins and Polymers
Our goal is to achieve a strong polymers market position. Through the
dissolution of our Appryl joint venture we acquired operational control of a
polypropylene plant at Grangemouth, UK. The Solvay deals increase our
polypropylene business and our interests in global HDPE and the additional 50%
share of Erdoelchemie (now called BP Cologne) represents an increase of some 10%
of our total chemicals production volumes. The Veba acquisition further enhances
our olefins production capability. In addition to these business-repositioning
changes, we will continue to invest in our existing businesses. We aim to build
on our existing technology base, which includes metallocene catalyst, the
proprietary technology used in Innovene, our gas-phase polyethylene production
process. Our product portfolio is biased to differentiated products, such as
HDPE and polypropylene, which are further enhanced as a result of the Solvay
transaction.
Products
We produce and market the basic petrochemical building blocks, known as
feedstocks, that are used primarily as raw material for other chemical products.
Feedstock chemicals are derived from the steam cracking of liquid and gaseous
hydrocarbons. The olefins - ethylene, propylene and butadiene - are produced by
crackers at Grangemouth, UK; Lavera, France (Naphtachimie - BP 50%); Cologne,
Germany and Chocolate Bayou, Texas. Olefins are also manufactured by Ethylene
Malaysia Sdn. Bhd. (BP 15%) at Kertih, Malaysia. Our production share of the
Veba crackers at Gelsenkirchen and Munchmunster will be added during 2002. These
crackers produce the raw materials for the production of derivative products
including polyethylene, polypropylene, acrylonitrile, styrene, ethanol and
ethylene oxide, which are also produced at various BP plants.
50
The polymers product line includes polypropylene, used for moulded
products, fibres and films; polyethylene, used for packaging, pipes and
containers; and styrene polymers, used in packaging and containers. We are the
second-largest producer of polypropylene in the world. Polypropylene is
manufactured at Chocolate Bayou, Deer Park and Cedar Bayou, Texas; Antwerp and
Geel, Belgium; Sarralbe, France and at Carson City, California. In addition, BP
operates a new polypropylene plant at Grangemouth, UK, commissioned during 2000,
and from 2001 we have an interest in the manufacturing joint venture at Lavera,
France. BP has its own proprietary polypropylene technology.
During 2001 BP gained clarification on the license to operate with
metallocene catalysts for its Innovene gas phase polyethylene process, following
an agreement between BP and other interested parties. The combination of
metallocene catalysts with the Innovene process produces differentiated
polyethylene film products that have an improved balance of performance and
processability compared to traditional metallocene or Ziegler-Natta based
materials.
We are one of Europe's leading producers of polyethylene; the world's most
widely used plastic. BP operates linear low-density polyethylene (LLDPE) plants
at Grangemouth in the UK and Cologne in Germany. Cologne also produces
low-density polyethylene (LDPE). We also produce LLDPE through PT Peni (BP 75%)
at Merak, Indonesia and through Polyethylene Malaysia Sdn. Bhd. (BP 60%) at
Kertih, Malaysia. BP Solvay Polyethylene Europe (BP 50%) has HDPE plants at
Grangemouth, UK; Antwerp, 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 operate styrene monomer plants at Texas City, Texas in the USA and Marl
in Germany. Polystyrene plants are operated at Marl and Wingles in France and
Trelleborg in Sweden. Expanded polystyrene plants are operated at Wingles and
Marl.
Major Activities
-- A 270-ktepa ethylene expansion at Grangemouth was commissioned late in
2001. The expansion boosts Grangemouth's ethylene capacity to 1
million tonnes. This additional production will feed new derivative
plants at both Grangemouth and Hull.
-- BP completed the purchase of Bayer's 50% stake in Erdoelchemie
(renamed BP Cologne) in May 2001.
-- The transaction with Solvay has made BP the world's second largest
producer of polyproylene (and the largest in North America) and
positioned BP as the world's fourth-largest polyolefins producer.
However, due to the current difficult business environment, we idled
205 ktepa of polypropylene capacity at Chocolate Bayou in the fourth
quarter of 2001 and in March 2002 we announced its permanent closure.
Also in March 2002 we announced the closure of our 261 ktepa
polypropylene facility at Cedar Bayou.
-- Restructuring programmes were begun at sites in Cologne, Lavera and
Grangemouth to realize incremental integration value.
-- The company announced its intention to shut down an older polyethylene
production unit, Rigidex 2, within the Grangemouth chemicals site. BP
also closed its LDPE manufacturing operations at Wilton on Teesside
due to difficult market conditions.
-- During 2001 the Chocolate Bayou and Texas City sites were integrated
into a single management structure to increase standardization and
take advantage of the overall scale and buying power of the combined
BP chemicals and refining activities in south Houston.
-- A major fire at Chocolate Bayou in February 2001 was managed safely
and efficiently with operations restored by July and with minimal
impact to customers or internal businesses. Record production volumes
were achieved in October as operations became fully restored.
-- Late in 2001 we increased our interest in the Carson City refinery
polypropylene unit from 67% to 85%.
-- In light of continuing difficult market conditions in the Philippines,
BP is reassessing its involvement in the Bataan Polyethylene Co. plant
(BP 39%).
-- In December 2001 BP, Sinopec and SPC announced the formation of SECCO
(BP 50%) which plans to build a $2.7 billion petrochemicals complex
near Shanghai. The complex is expected to begin operation in 2005. In
January 2002 we announced a loan agreement worth $1.8 billion with
nine domestic and two international banks to fund two-thirds of the
project.
51
Intermediates
As with Aromatics, we aim to be number one or two in terms of market share
in markets where we compete. New investments will build on existing leadership
positions and distinctive technology.
Products
The intermediate businesses add value to raw materials produced by our
other chemicals businesses and include acetic acid and its derivatives; a range
of solvents and industrial chemicals; linear alpha-olefins (LAOs); polybutenes;
acrylonitrile; TMA, used by the automotive, construction, consumer goods, and
packaging industries; butanediol (BDO), used in synthetic materials and
engineering plastics; and maleic anhydride (MAN), used in a wide range of
plastics and resins.
We are a major supplier of acetic acid, a versatile chemical used in a
variety of products such as foodstuffs, textiles, paints, dyes and
pharmaceuticals. BP has acetyls operations in Europe, the USA, 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%)
In Korea, the Asian Acetyls Company (BP 34%) operates a 150-ktepa vinyl
acetate monomer (VAM) plant. A new 250-ktepa VAM plant at Hull was commissioned
during 2001 and the VAM plant at Baglan Bay in Wales is due to close during
2002.
BP is a leading supplier of polybutene which we manufacture at Whiting,
Indiana and at Lavera, France. A plant at Texas City, Texas is due to cease
production in 2002. Polybutene is used in fuel additives, lubricants, adhesives,
sealants, cable filling compounds, personal care products, tackified
polyethylene, explosives and many other products.
LAOs are used in the production of polyethylene, for the manufacture of
plasticizers for polyvinyl chloride, for the manufacture of poly alpha-olefins
for synthetic lubricants, for the production of biodegradable surfactants, in
synthetic-based drilling muds for the oil field and for a host of other
intermediate and final products. LAOs are produced at our facilities in
Pasadena, Texas; Joffre, Alberta and Feluy, Belgium.
BP is a leading supplier of poly alpha-olefins, high viscosity index
materials primarily used in the production of high performance, environmentally
friendly, synthetic lubricants and motor oils. These materials are manufactured
at our facilities in Deer Park, Texas and Feluy, Belgium.
BP is the world's largest producer and marketer of acrylonitrile. We
operate two acrylonitrile plants at Green Lake, Texas and Lima, Ohio. Green
Lake, with a capacity of 460 ktepa, is the largest acrylonitrile production site
in the world. Acrylonitrile is also produced at Cologne, Germany and through a
capacity rights agreement with Sterling Chemicals at Texas City, Texas.
Additionally, BP is the world's largest producer and marketer of acetonitrile,
primarily sold into pharmaceutical applications.
The anhydride business unit produces TMA and MAN at Joliet, Illinois, and
is the world's largest producer of TMA. In 2000, we entered the global market
for BDO using our proprietary technology in a world-scale plant at Lima, Ohio.
BDO and its derivatives are used in pharmaceuticals, a variety of personal care
products, plastics, auto parts and sports clothing.
Major Activities
-- The new 220-ktepa ethyl acetate plant at Hull was commissioned
successfully in June 2001. The 110-ktepa ethanol plant at Grangemouth
is nearing mechanical completion and is due to start up during 2002.
The ethyl acetate investment is based on BP's innovative 'direct
addition' method, which uses ethylene and acetic acid and does not
require ethanol as a raw material. To supply ethylene to the new
plants a pipeline has been installed between Teesside and Hull,
linking into the UK ethylene network.
-- First production was achieved from a new 250-ktepa VAM plant at Hull
late in 2001. The plant uses the proprietary BP LEAP technology based
on a fluid bed catalyst. The plant will replace production from Baglan
Bay and the Enichem toll manufacturing agreement at Porto Marghera.
The capacity of the new plant is planned to increase to 300 ktepa.
-- We completed construction of a 250-ktepa LAO facility at Joffre in
Alberta, Canada. The plant started up in the fourth quarter of 2001
and is operating smoothly.
52
-- During 2001, both the phthalic anhydride and phthalates plants at Hull
were closed. These units are being demolished during 2002. Late in
2001, we announced the closure of the S24 Acetate plant at Hull. The
plant, which manufactured 175 ktepa of ethyl acetate, iso-propyl
acetate and butyl acetate closed at the end of 2001. Also during the
fourth quarter of 2001 we announced the sale of our butyl acetate
business to Ineos. The sale will include the transfer of the 60-ktepa
plant at Antwerp.
-- We announced the cessation of the production of alcohols on our site
at Pasadena, Texas. The 60-ktepa plant will stop during the fourth
quarter 2002 when this site will concentrate on the production of
LAOs.
-- The proposed 65-ktepa TMA plant at our existing PTA complex in
Kuantan, Malaysia has advanced to construction bid stage. As a
consequence of current market conditions, this TMA plant construction
has been temporarily suspended.
53
OTHER BUSINESSES AND CORPORATE
Other Businesses and Corporate comprises Finance, BP Solar, the Group's
coal asset and aluminium asset, its investments in PetroChina and Sinopec,
interest income and costs relating to corporate activities worldwide.
Years ended December 31,
------------------------
2001 2000 1999
----- ----- -----
($ million)
Turnover................................................. 783 249 198
Total replacement cost operating loss.................... (556) (1,110) (826)
Total assets............................................. 8,073 11,970 2,643
Capital expenditure and acquisitions (a)................. 563 30,616 284
-----------
(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.
Finance co-ordinates the management of the Group's major financial assets
and liabilities. From locations in the UK, Europe, the USA and the Asia-Pacific
region, it provides the link between BP and the international financial markets,
and makes available a range of financial services to the Group including
supporting the financing of BP's projects around the world.
Moody's and Standard and Poor's have assigned long-term debt ratings to BP
of Aa1 and AA+, respectively.
Finance has in place a European Debt Issuance Programme (DIP) and a US
Shelf Registration under each of which the Group may raise an aggregate of $6
billion of debt for maturities of one month or longer. At March 26, 2002, the
amount drawn down against the DIP was $564 million, and $1,500 million against
the US Shelf Registration.
BP Solar. Our solar energy business increased production and shipments by
30% compared with 2000, selling a total of 55 megawatts (MW) of solar panel
generating capacity (2000, 42 MW). Major projects in 2001 included the purchase
of a new Madrid facility that will be one of the world's largest solar plants
when the production facility upgrade is completed in late 2002, and the
completion of a $48 million project to power 150 Philippine villages - the
largest solar energy project to date.
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 a 2.2%
interest in each company. Separately, BP announced plans to form joint ventures
with both companies: in natural gas marketing and fuels retailing with
PetroChina and in fuels and petroleum products marketing and chemicals with
Sinopec. PetroChina and Sinopec are two of China's major companies in the oil
and chemicals businesses.
Research, technology and engineering activities are carried out by each of
the major business streams on the basis of a distributed programme coordinated
by the BP Technology Council. This body provides leadership for scientific,
technical and engineering activities throughout the Group and in particular
promotes cross-business initiatives and the transfer of best practice between
businesses. In addition, a group of eminent industrialists and academics form
the Technology Advisory Council, which advises senior management on the state of
technology within the Group and helps identify current trends and future
developments in technology.
Research and development is carried out using a balance of internal and
external resources. Involving third parties in the various steps of technology
development and application enables a wider range of technology solutions to be
considered and implemented, improving the productivity of research and
development activities.
54
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.
Renewables and alternative fuels. In renewables we are further building
expertise in wind energy with plans to construct a wind farm at our jointly
owned Nerefco refinery in the Netherlands. We are exploring market opportunities
for hydrogen and fuel cells through participation in various industry projects
and organizations promoting fuel cells and hydrogen fuels. Examples include a
joint project with DaimlerChrysler, First Bus, Transport for London and the
Energy Savings Trust to introduce three hydrogen fuel cell buses to England's
capital; and BP and Singapore's Economic Development Board (EDB) have signed a
letter of intent to build hydrogen refueling stations for future Singapore
motorists.
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 periodically.
Integrated supply and trading. During 2001, BP brought together the trading
activities in Gas and Power, Refining and Marketing and Finance under single
leadership. As Chemicals develops trading activities, they will be included as
well. The financial results of the trading activities will remain with the
business streams. This change provides the opportunity to improve our knowledge
transfer, risk management, control and assurance processes and to optimize our
systems investment.
55
REGULATION OF THE GROUP'S BUSINESS
United Kingdom
Licensing. Pursuant to, among other things, The Petroleum Act 1998, all
petroleum existing in its natural condition in strata in the UK or beneath its
territorial waters (including its continental shelf) is the property of the
Crown, and licences to explore for and produce it may be granted, subject to
conditions, by the Secretary of State for Trade and Industry (Secretary of
State). These conditions include provisions relating to the term of the licence,
the imposition of specific drilling obligations, environmental protection
controls, controls over the development and decommissioning of oil and natural
gas fields (including restrictions on production) and the payment of royalties.
Development of oil and natural gas reserves. The development and production
of UK oil and natural gas reserves (including rates of production) require the
approval or consent of the Secretary of State. There have been a number of
policy statements by various UK Governments over the years with respect to
production controls. Although successive Governments have made it clear that the
imposition of production cut-backs in order to facilitate a coherent depletion
policy has been kept under review, the steps taken by the Government since the
early 1980s have tended to concentrate on encouraging exploration, development
and production and no significant cut-backs of previously agreed rates of
production are known to have been imposed.
Other controls. In addition to the regulatory powers of the Government
referred to above, the Secretary of State has wide powers over the oil field
operations, including gas flaring, the installation, use and tariffs of
sub-marine pipelines, the construction or expansion of refining capacity and
powers to impose programmes for the eventual decommissioning of offshore
installations. Furthermore, the Secretary of State for Transport has powers to
control the positioning of offshore installations if the chosen location is in
or is close to a shipping lane. The UK Health and Safety Executive has wide
powers and duties in relation to offshore health and safety. BP is also subject
to European Union legislation, in particular the Procurement Directive which
regulates the procedure for awarding major contracts.
Petroleum revenue tax. Petroleum revenue tax (PRT) was abolished in the
Finance Act 1993 in respect of oil and natural gas fields given development
consent on or after March 16, 1993 (Non-Taxable Fields). Profits from
Non-Taxable Fields are charged to corporation tax under general principles. PRT
is still charged on profits from fields given development consent before that
date (Taxable Fields). PRT is charged in relation to Taxable Fields on profits
from oil (which includes natural gas except where specifically excluded by
statute) won under licences granted under either the Petroleum (Production) Act
1934 or the Petroleum (Production) Act (Northern Ireland) 1964. It is charged on
a field-by-field basis, at the rate of 50% for chargeable periods ending after
June 30, 1993 (75% for periods ending on or before that date), on the assessable
profit arising in each chargeable period (normally the six months ending on June
30 and December 31 in each year), as reduced by any allowable losses and by an
oil allowance (unless the maximum amount of oil allowance has already been
used), and subject in certain years to an overall limit (safeguard). PRT is also
chargeable on any consideration received in connection with the use by other
fields and the disposal of certain 'qualifying assets', the expenditure on which
is allowable for PRT, subject to an allowance in the case of the use of assets
by fields which are themselves liable to PRT.
The assessable profit reflects, very broadly, the market value of oil won
less the costs of discovery and production, including any Government royalties
payable. Interest and other financing costs are not deductible in determining
the assessable profit; instead, certain costs are designated as qualifying for a
supplement of 35% (uplift). Uplift ceases for costs incurred after the end of
the chargeable period in which the field's cumulative income exceeds its
cumulative expenditure (payback).
Oil allowance exempts certain amounts from PRT. For each onshore field and
offshore field given development consent before April 1982, an allowance of up
to 250,000 tonnes of oil per chargeable period is available, subject to a
cumulative total of 5 million tonnes. For each onshore field and each offshore
field situated in the Southern Basin of the North Sea given development consent
after March 1982, the oil allowance for chargeable periods ending after June 30,
1988 is 125,000 tonnes per chargeable period and the cumulative total is 2.5
million tonnes. For each offshore field not situated in the Southern Basin given
development consent after March 1982, the allowance is 500,000 tonnes per
chargeable period subject to a cumulative total of 10 million tonnes. The oil
allowance is shared by the participants in each field in proportion to their
shares of oil. Safeguard provides that the total PRT payable in respect of a
field is limited to 80% of the amount (if any) by which the PRT profits for a
chargeable period (specially adjusted for this purpose) exceed 15% of
accumulated expenditure (as adjusted). Safeguard remains available after payback
has been reached for half as many periods again as it took to reach payback from
the first chargeable period.
56
Allowable losses in any chargeable period can be set off against the
assessable profits of subsequent or, after making an appropriate claim, previous
periods from the same field but, in relation to losses arising in respect of
chargeable periods ending after June 30, 1993, the PRT repayment plus any
interest thereon arising from the set-off of losses against profits of previous
periods cannot exceed 60% of the losses set off (85% in respect of chargeable
periods ending after June 30, 1991 and on or before June 30, 1993). In addition,
relief is available against the assessable profit from a field for certain
expenditure incurred outside the field. There are restrictions to prevent the
obtaining of relief for expenditure incurred in connection with Non-Taxable
Fields against profits from Taxable Fields. Exploration or appraisal expenditure
incurred on or after March 16, 1983 and before March 16, 1993, in respect of an
area for which no development decision has been made, may be set against the
assessable profits of any Taxable Field together with any such expenditure
incurred prior to that date which is designated as abortive. There is no relief
for exploration and appraisal incurred after March 16, 1993 unless the Company
was already committed to it at that date and it is incurred on or before March
16, 1995. There is an additional transitional relief for exploration and
appraisal expenditure, subject to certain conditions, limited to a maximum of
(pound)10 million for expenditure incurred on or after March 16, 1993 and before
January 1, 1995. Finally, a loss from a Taxable Field in which the winning of
oil has permanently ceased which cannot be relieved against the assessable
profits of that field can be claimed against the assessable profit from any
other Taxable Field. The offset of reliefs is limited to prevent a company
buying into mature oil fields and setting pre-acquisition expenditures against
the assessable profits of that field.
Royalties. Royalty is charged on the value of production from certain
licences, in most cases payable at a rate of 12.5%. Royalty has been abolished
for fields which received development consent after March 31, 1982. Production
licences contain provision for Royalty to be charged and separate rules (called
modes) will apply dependant on where the licence is located and when it was
issued. There are seven separate modes for calculating Royalty. Royalty is
calculated by reference to six month chargeable periods (CP) ending on June 30,
and December 31, with a return and payment made two months after the end of the
CP. Certain modes provide for relief of conveying and treating expenditure. The
relief varies considerably depending upon which mode applies. Some modes provide
no relief for expenditure.
Corporation tax. Companies are also subject to corporation tax on their
profits or gains from oil extraction activities, although PRT is deductible in
computing any corporation tax liability. There are restrictions on using reliefs
from other activities against profits or gains from oil extraction activities,
or from the disposal of interests in oil or of assets used in connection with a
field in the UK or a designated area. There is also an exemption from capital
gains taxation and capital allowance clawback for certain exchanges of licence
interests before the development stage. An election can be made in relation to
expenditure incurred after June 30, 1991 for 100% reliefs for certain net
offshore decommissioning expenditure. Losses created by these decommissioning
reliefs are available for set-off against profits of the previous three years.
United States
Tax. The State of Alaska imposes various taxes on the Group's operations in
Alaska. At present, these include a severance tax on oil and natural gas
produced, an ad valorem tax on all oil and gas exploration, production and
pipeline equipment and a corporate income tax on companies doing business in
Alaska. Following the Exxon Valdez oil spill, the State of Alaska passed an act
to finance the State's Oil and Hazardous Substance Release Response Fund by
imposing a conservation surcharge of $0.05 per barrel on all oil subject to the
State's oil and gas properties production tax. Subsequently, the State amended
the surcharge to suspend $0.02 per barrel of it when the balance in the Response
Fund exceeds $50 million, and as a result the net surcharge is $0.03 per taxable
barrel unless there is a spill that draws the Fund's balance below $50 million.
Further, losses occurring in connection with a catastrophic oil discharge are
not deductible as business expenses in determining the gross value of oil for
tax purposes in the State of Alaska.
Pipeline regulations. The Interstate Commerce Act requires common carriers
engaged in the transport by pipeline of oil in interstate or foreign commerce to
file tariffs with the Federal Energy Regulatory Commission (FERC) showing all
rates, classifications, rules and practices between all points on their system.
It also prohibits them from collecting any different compensation for
transportation from that specified in their approved tariffs. Third parties, or
the FERC on its own motion, may initiate an investigation of any proposed
tariff, which involves the scheduling of a hearing. If the FERC, at the
conclusion of a hearing, finds that a new or increased rate is unreasonable or
discriminatory, or otherwise in violation of the Interstate Commerce Act, it may
order the carrier to cease and desist from charging that rate, may prescribe a
rate for the future and order refunds to shippers of collected amounts found to
be unreasonable. Similar corresponding provisions at a state legislative level
and enforced through a state regulator may also apply to common carriers engaged
in the transport by pipeline of oil in intrastate commerce.
57
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 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.
Kyoto Protocol
In December 1997, at the Third Conference of the Parties to the United
Nations Framework Convention on Climate Change in Kyoto, Japan, the participants
agreed on a system of differentiated internationally legally binding targets for
the first commitment period of 2008-2012. The range of targets in Annex I
countries (OECD, former Soviet Union and Eastern Bloc countries) against 1990
levels of emissions is from -8% to +10% for a basket of the six main greenhouse
gases. The USA agreed, subject to ratification by the Senate, on a reduction of
7%, and the European Union on a reduction of 8%. EU member states have
undertaken differentiated commitments on the basis of 'burden sharing' to meet
the overall Community target. If these targets are to be met, some reduction in
the use of fossil fuels would be required within countries which have ratified
the Kyoto treaty, although a portion of the reduction in emissions will be
delivered by switching to lower carbon fuels (for example natural gas). 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).
At the Seventh Conference of the Parties to the United Nations Framework
Convention on Climate Change, held in Marrakech in November 2001, broad
agreement was reached on many of the outstanding issues with the Kyoto Protocol.
In order to achieve this, a number of concessions were made. The result is that
if implemented, the agreement will be likely to lead to approximately a 1.5%
reduction in greenhouse gas emissions in total across those countries expected
to participate. Overall, global emissions will continue to increase, as the
energy demand of the developing nations continues to increase strongly. It is
therefore likely that, in the medium term, the global demand for fossil fuels
will increase, with gas taking the largest share of that growth.
58
Legislation and Regulation
The following is a summary of significant health, safety and environmental
legislation affecting the Group in 2001.
United States
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 on chemical plant, refinery,
marine and distribution terminals; and risk management plans for storage of
hazardous substances.
Title V of the Clean Air Act requires major emission sources to obtain new
air permits. This permitting effort is underway at the Group's US operations.
Title V also requires more comprehensive measurement of specified air pollutants
from major emission sources. Two aims of this regulation are to provide
regulating bodies with accurate data on emissions from major sources, and to
enable regulatory authorities to better evaluate compliance with applicable
emission limitations.
The Risk Management Plan regulations under the Clean Air Act require that
any non-exempted facility that processes or stores a threshold amount of a
regulated substance prepares and implements a risk management plan to detect,
prevent and minimize accidental releases. The primary components of the
programme require undertaking an offsite hazard assessment, preparing a response
plan and dialogue with the local community.
Additionally, the Clean Air Act imposes specifications for motor vehicle
fuels that significantly impact petroleum refining, transportation and marketing
operations. In nine urban areas with the highest ozone levels, reformulated
gasoline (RFG) containing oxygenates, lower levels of benzene, lower volatility
and reduced nitrogen oxides emissions was introduced beginning January 1995. The
levels of volatility and nitrogen oxides emissions standards were tightened
again in January 2000, with the introduction of Phase II RFG. BP manufactures
and markets fuels in some of these nine areas, as well as in other areas that
chose to join the RFG programme.
Since 1992, gasoline sold during the winter in approximately 40
metropolitan areas with higher carbon monoxide levels must have higher levels of
oxygenates such as methyl-tertiary-butyl-ether (MTBE) and ethanol. BP is
providing such oxygenated fuels in a number of US markets. Recently some
environmental groups and legislators have expressed opposition to the continued
use of MTBE as an oxygenate. California has recently announced a ban on the use
of MTBE, effective January 2003, due to groundwater contamination and public
health concerns. Other states and the US Congress have either passed or are
considering legislation to restrict or eliminate the use of MTBE. Some
metropolitan areas have been able to achieve compliance with carbon monoxide
standards and terminate their wintertime oxygenated fuels programmes.
At the end of 1999, the US Environmental Protection Agency (EPA)
promulgated its Tier 2/Gasoline Sulphur Programme. This programme will impose
new tailpipe emission standards on all passenger vehicles while lowering the
allowable gasoline sulphur content. The gasoline sulphur standards will be
phased in from 2004 to 2006.
Beginning 1993, the Clean Air Act limited highway diesel fuel sulphur
content to 500 parts per million. BP has been producing this fuel in many of its
US markets. At the end of 2000, the EPA adopted rules reducing highway diesel
sulphur limits to 15 parts per million. These rules will take effect in June
2006. The Act also requires service stations located in certain ozone
non-attainment areas to install equipment to capture gasoline vapours released
during refueling.
In 2001, EPA finalized new gasoline toxic emission baseline requirements,
effective January 2002. This requires refiners to maintain current levels of
over-compliance with toxic emissions performance standards that apply to RFG and
anti-dumping standards that apply to conventional gasoline. Both the new
gasoline and highway diesel rules will necessitate significant capital
expenditures additions or upgrades to current refining facilities and may render
some product lines or facilities uncompetitive.
The Clean Air Act also requires installation of 'maximum achievable control
technology' (MACT) over a ten-year period at certain types of industrial
facilities that release certain specified toxic chemicals. Additional controls
could be required if the EPA determines that an unacceptable residual risk
remains after installation of MACT. The EPA has finalized MACT control
requirements for certain categories of chemical plants, refineries, gasoline
marketing terminals and marine terminals. Additional regulations on some sources
in petroleum refineries were proposed in 1998. These were expected to be
finalized in 2001 but were deferred by the new Administration. They will likely
be promulgated in 2002 with compliance required 3 years later. In order to
comply with the National Ambient Air Quality Standards, which were promulgated
to protect public health, some states will be requiring large reductions in the
emission of nitrogen oxides. This will require the addition of significant new
controls on some refineries and chemical operations in the US.
59
During 2001, BP entered into a consent decree with the EPA and several
states that settled alleged violations of various Clean Air Act requirements at
BP's refineries. This settlement, which largely addresses emissions of sulphur
dioxide and nitrogen dioxide, 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 payment of a $10 million penalty. The cost
of installation of additional controls will be accounted for in line with BP's
accounting policy for environmental expenditure. A one-time payment of the $10
million penalty was incurred in 2001.
BP is also in the third year of implementing a plea agreement with the US
Justice Department to develop, implement and maintain a nationwide environmental
management system (EMS) consistent with the best environmental practices at all
Group facilities engaged in oil exploration, drilling and/or production in the
US and its territories. This programme is expected to cost approximately $15
million.
The Clean Water Act regulates the discharge of wastewater and other
pollutants into US waters. Facilities are required to obtain permits for most
discharges, install control equipment and implement operational controls and
preventative measures. Requirements under the Clean Water Act have become more
stringent in recent years, including coverage of storm and surface water
discharges at many facilities and increased control of toxic discharges.
During 1995 a final federal rule was issued regarding protection of the
Great Lakes watershed which will have local and national impacts on water
protection requirements. In July 2000, EPA promulgated a new rule that would
impose total maximum daily limits (TMDLs) on discharges that would impair
achievement of water quality objectives in many waterways. The US Congress did
not provide EPA with funding to implement the rule, but work on TMDLs is ongoing
under an earlier rule and new, more stringent limits on discharges from
industrial facilities are expected to result. Many industries challenged EPA's
new rule in court and in response, EPA deferred implementation of the rule while
it reassessed its requirements.
The Oil Pollution Act of 1990 (the Oil Pollution Act or OPA 90)
significantly increased oil spill prevention requirements, spill response
planning obligations and spill liability for tank vessels (tankers and barges)
transporting oil, offshore facilities (such as platforms) and onshore terminals.
To provide funds for response to and compensation for oil spills when the
spiller is unable to do so, the Oil Pollution Act created a $1 billion fund
which is funded by a tax on imported and domestic oil.
The Oil Pollution Act requires that all new tank vessels operating in US
waters have double hulls, and the phase out, between the years 1995 and 2015, of
existing vessels without double hulls. Oil transporters, terminals and other
handling facilities are most affected by the expanded technical and operational
requirements under OPA 90. Regulations require businesses to provide
certificates of financial responsibility and to maintain facility response plans
that, among other things, identify and prepare for worst case spill scenarios.
Owners and operators of covered facilities and vessels must also conduct
emergency response training, consistent with regulations and with area and
national contingency plans.
The Prince William Sound port-specific vessel escort plan required by
regulations that became effective late in 1994, was updated during 1995,
including operational requirements such as enhanced tanker assist capabilities,
rudder failure response procedures, and reduced speed in the Valdez Narrows,
plus directives on communications and training. The latest Vessel Escort &
Response Plan (VERP) was published in December 2001. It reflects significant
enhancements made to the escort system such as the requirement to use the most
powerful Voith-Schneider tugs in the US and equally powerful tractor tugs.
BP has set performance objectives to enhance emergency preparedness and
crisis management at all facilities, and to assure compliance with all related
laws such as the Oil Pollution Act. These objectives are designed to be met
through appropriate assessment, planning, training and routine exercises, and by
the provision or identification of sufficient human and physical resources. BP
has established a National Strike Team, the BP Americas Response Team, which
consists of approximately 180 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. RCRA
requirements have become increasingly stringent in recent years, as the EPA
expands the definition of hazardous wastes. BP facilities generate and handle a
number of wastes regulated by RCRA and have units that have been used for the
storage, handling or disposal of RCRA wastes that are subject to investigation
and corrective action.
Under the Comprehensive Environmental Response, Compensation, and Liability
Act (also known as CERCLA or Superfund), waste generators, site owners, facility
operators and certain other parties may be strictly liable for part or all of
the cost of addressing sites contaminated by spills or waste disposal regardless
of fault or the amount of waste sent to a site.
60
Additionally, each state has laws similar to CERCLA. A federal tax on oil
and certain chemical products was enacted to fund a part of the CERCLA programme
but this tax has been suspended for several years while CERCLA reform
legislation is debated in the US Congress.
BP has been identified as a Potentially Responsible Party (PRP) under
CERCLA and similar state statutes at approximately 800 active sites. A PRP has
joint and several liability for site remediation costs and so BP may be required
to assume, among other costs, the share attributed to insolvent, unidentified or
other parties. BP has the most significant exposure for remediation costs at 63
of these sites. For the remaining sites, the number of PRPs ranges from 20 to
200. BP expects its share of remediation costs at these sites to be small. BP
has estimated its potential exposure at all sites where it has been identified
as a PRP and has accrued provisions accordingly. BP does not anticipate that its
ultimate exposure at these sites individually, or in the aggregate, will be
significant except as reported for ARCO in the matters below.
Pursuant to the authority provided under Superfund, the State of Montana
has pursued claims against ARCO for compensation alleging damage to natural
resources arising out of ARCO's predecessors' mining and mineral processing
activities. In addition, a tribe was granted a limited form of intervention in
the lawsuit, Montana vs. ARCO. The tribe, as alleged trustees, asserted claims
against ARCO for alleged injury to and loss of natural resources located in the
Clark Fork River Basin in southwest Montana. The United States Department of
Interior also stated an intention to make a claim for natural damages in the
Clark River Basin. These matters were settled in part in 1999, however,
remaining for disposition are the State's claims for $206 million for
restoration damages at several sites.
On June 23, 1989, the EPA filed a CERCLA cost recovery action against
Atlantic Richfield Company in the United States District Court for the District
of Montana, for the oversight costs at several of the Upper Clark Fork River
Basin Superfund sites. Litigation is proceeding on both the EPA's and ARCO's
counterclaims against various federal agencies. In the counterclaims, ARCO seeks
contributions from the federal agencies for remediation costs and for any
natural resource damage liability ARCO might incur in Montana vs. ARCO. The
settlements in Montana vs. ARCO, described above, resolved the claims and
counterclaims in US vs. ARCO pertaining to one significant site and may provide
a framework for possible future settlement of the remaining claims.
The Group is also subject to claims made for natural resource damage (NRD)
under several federal and state laws. This is a developing area under US law
which could significantly impact the cost of some cleanups. NRD claims have been
asserted by government trustees against several refineries and other company
operations.
Other significant legislation includes the Toxic Substances Control Act
which, among other things, regulates the development, testing, import, export
and introduction of new chemical products into commerce; the Occupational Safety
and Health Act which, among other things, imposes workplace safety and health,
training and process standards to reduce the risks of chemical exposure and
injury to employees; and the Emergency Planning and Community Right-to-Know Act
which requires emergency planning and spill notification as well as public
disclosure of chemical usage and emissions. The Occupational Safety and Health
Administration's Process Safety Management rule formalizes the procedures used
in identifying and minimizing safety risks at facilities that use certain
chemicals in excess of threshold quantities and also in conducting formal
documented hazard reviews of covered processes.
In 1993 the South Coast Air Quality Management District (AQMD), which
regulates emissions from stationary sources within a four county area of
Southern California, including Los Angeles County, adopted a programme requiring
phased reductions of oxides of nitrogen and oxides of sulphur for certain
facilities, including our Carson Refinery. The aggregate annual emissions of
these pollutants will be reduced by 2003 by 80%. AQMD has created a pollution
credits programme, in which we participate, that provides flexibility in
achieving the requisite levels of emission reductions.
See also Item 8 -- Financial Information -- Legal Proceedings.
61
United Kingdom and European Union
A European Commission (the Commission) directive for a system of Integrated
Pollution Prevention and Control (IPPC) was approved in 1996. This system is
based upon ensuring environmental quality standards are not exceeded and the
application of Best Available Techniques (BAT) taking into account cost-benefit
analysis as a holistic approach. In the event that the use of BAT will fail to
meet Environmental Quality Standards (EQS), plant emissions must be reduced
further to meet the EQS. This encompasses, among other things, most activities
and processes undertaken by the oil industry within the European Union. The
European Commission has stated that it hopes that all processes to which it
applies will be licensed by July 2005. All plants must be upgraded to BAT
standards by November 2007. In the UK, the IPPC directive was implemented
through the Pollution Prevention and Control regulations, which replaced UK
Integrated Pollution Prevention and Control.
The European Union Large Combustion Plant Directive sets emission limit
values for sulphur dioxide, nitrogen oxides and particulates from large
combustion plants. It also requires phased reductions in emissions from existing
large combustion plants. Implementation by Member States was required by June
1990. In the UK, it has been given effect through the authorization mechanism in
Part 1 of the Environmental Protection Act 1990. Large combustion plants
required an IPC application to be made by April 30, 1991. Upgrading to the
BATNEEC standard is required at the earliest opportunity, at the latest by April
1, 2001. The European Commission has considered proposals to impose emission
limit values on small combustion plants. A revised Large Combustion Plant
Directive has been agreed and implementation is required by November 27, 2002.
Plants will have to comply by 2008.
As part of its overall programme to combat air pollution, the European
Union (EU) has set stringent emission limits for new cars and commercial
vehicles which are being implemented in stages. Beginning October 1994, the
sulphur content of diesel fuel was limited to 0.2% and from October 1996 the
limit was further reduced to 0.05%. Heating oils were initially limited to 0.2%
with further reductions subject to review. In August, the Federal German
Government adopted a regulation to encourage early introduction of low sulphur
transport fuels by setting differential excise taxes for gasoline and diesel
with maximum 50 parts per million sulphur content from November 2003, and for a
maximum of 10 parts per million from January 2001. It also proposed that 10
parts per million sulphur fuels should be adopted at EU level. Implementation of
the German regulation depends on tax derogations being agreed by the Commission
and the other member states. The Commission made it clear that it will not
consider 10 parts per million sulphur fuels within the current Auto/Oil
Programme for implementation in 2005.
In 1998, the EU adopted directives to set emission limits for cars and
light vehicles to apply from 2000, together with specifications for gasoline and
diesel fuel to apply from that date. Some member States indicate that they need
energy product taxes to enable them to meet their Kyoto commitments, within the
EU burden sharing agreement, and are already implementing national legislation.
The Commission is also undertaking a second Auto/Oil Programme to propose
changes to other gasoline and diesel fuel specifications from 2005, as well as
non-technical measures designed to help meet air quality targets.
In April 1999, the EU adopted a directive to further reduce the sulphur
content of liquid fuels, but excluding marine bunker fuel oil, and marine gas
oil used by ships crossing a frontier between a third country and an EU Member
State. Sulphur in gas oil will be limited to 0.2% from July 2000, and 0.1% from
January 2008. From January 2003, sulphur in heavy fuel oil will be limited to
1%, except where use of heavy fuel oil up to 3% sulphur can be used in
combustion plants without exceeding specific emission limits, and provided that
local air quality standards are met.
As part of its overall approach to improving air quality, in 1997 the
Commission proposed its Acidification Strategy, and followed this with its
proposal for a strategy to combat tropospheric ozone. The Ozone Strategy was
adopted in 1998. Four air quality targets have been adopted as Directives, two
more have been proposed by the Commission and a target of 120 micrograms per
cubic metre for ozone itself was proposed in 1999, together with a proposal for
national emission ceilings for the main polluting emissions. Upon adoption by
the Council, these targets and ceilings will be the reference point for further
environmental controls of industrial installations at Community and Member State
levels.
The carbon monoxide and benzene directive is the second daughter Directive
of 96/62/EC on ambient air quality assessment and management and prescribes,
among other things, limit values and alert thresholds for carbon monoxide (CO)
and benzene. For benzene, a limit value of 0.005 milligrams per cubic metre
averaged over a calendar year applies. A margin of tolerance of 100%, to be
progressively eliminated from 2003 to 2010, would apply. For carbon monoxide, a
limit value of 10 milligrams per cubic metre will apply with a rolling 8-hour
averaging period and a 50% margin of tolerance on entry into force, to be
reduced to zero from 2003 to 2005.
As part of its ozone strategy, the EU has taken action on volatile organic
compounds (VOCs). In late 1994, the European Union adopted the so-called Stage 1
VOC controls which require a 90% cut in emissions over ten years from petroleum
transport and storage. In November 1996, the Commission proposed a directive on
control of emissions of organic solvents from the solvent-using industry which
has the goal of combating low-level ozone by setting emission limits and, as an
alternative, targets to be met by national plans. Existing installations would
be required to reach compliance by 2007. This proposal was adopted as a
Directive during 1998.
62
EU emission reduction requirements together with reduced sulphur content in
fuels may require significant modifications or capital expenditure at facilities
and could make the continued operation of particular product lines and
facilities uncompetitive.
As part of a package to stabilize carbon dioxide emissions at 1990 levels
by the year 2000, the European Commission proposed a combined carbon dioxide
energy tax. In March 1997, the Commission proposed instead an energy tax that is
intended to be fiscally neutral when applied by Member States. Though formally
the proposal replaces the carbon dioxide energy tax proposal that had been
blocked in Council, it has as its main objective to provide a harmonized
framework by setting minimum levels for national excise taxes on energy
products, and to allow Member States greater flexibility to offer tax incentives
based on environmental criteria, whilst avoiding barriers to trade within the
Single Market. Maximum sulphur levels for gasoline and diesel fuels to apply
from 2005 were also agreed as 50 parts per million, which is 0.005% , and 35%
maximum aromatic content for gasoline from the same date. In 1999, this was
followed by emission limits for heavy commercial vehicles, also based on the
Auto/Oil Programme conclusions. The Commission will make further proposals based
on the results of its Auto/Oil II Programme and the review of the sulphur
content of gasoline and diesel undertaken in parallel.
The European Commission is committed to a harmonized EU approach to
liability for environmental damage. This follows a 'green (discussion) paper' in
1992 that focused on a strict liability approach. The Commission issued a
proposed directive in January 2002.
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.
63
ORGANIZATIONAL STRUCTURE
The significant subsidiary undertakings of the Group at December 31, 2001
and the Group percentage of equity 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 (*).
Subsidiary Country of
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 100 Scotland Exploration and production
Jupiter Insurance 100 Guernsey Insurance
France
BP France 100 France Refining and marketing and chemicals
Germany
Deutsche BP 100 Germany Refining and marketing and chemicals
Netherlands
BP Capital BV 100 Netherlands Finance
BP Nederland 100 Netherlands Refining and marketing
Norway
BP Amoco Norway 100 Norway Exploration and production
Spain
BP Espana 100 Spain Refining and marketing
Middle East
BP Egypt Gas 100 USA Exploration and production
BP Egypt 100 USA Exploration and production
Africa
BP Southern Africa 75 South Africa Refining and marketing
Far East
Indonesia
BP Kangean 100 Indonesia Exploration and production
Singapore
BP Singapore Pte* 100 Singapore Refining and marketing
Australasia
Australia
BP Australia 100 Australia Integrated oil operations
BP Developments Australia 100 Australia Exploration and production
BP Finance Australia 100 Australia Finance
New Zealand
BP Oil New Zealand 100 New Zealand Marketing
Western Hemisphere
Canada
BP Canada Energy 100 Canada Exploration and production
Trinidad
BP of Trinidad and Tobago 90 USA Exploration and production
Amoco Trinidad (LNG) B.V. 100 Netherlands Exploration and production
USA
Atlantic Richfield Co. 100 USA (
BP America* 100 USA (
BP Amoco Chemical Company 100 USA ( Exploration and production,
BP America Production Company 100 USA ( gas and power, refining
BP Company North America 100 USA ( and marketing, pipelines
BP Corporation North America 100 USA ( and chemicals
BP Products North America 100 USA (
BP West Coast Products 100 USA (
Standard Oil Co. 100 USA (
64
ITEM 5 -- OPERATING AND FINANCIAL REVIEW AND PROSPECTS
GROUP OPERATING RESULTS
Years ended December 31,
--------------------------
Highlights 2001 2000 1999
----- ----- -----
Turnover.......................................... ($ million) 174,218 148,062 83,566
Total replacement cost operating profit........... ($ million) 16,135 17,756 8,894
Replacement cost profit before exceptional items.. ($ million) 9,880 11,214 5,330
Replacement cost profit for the year.............. ($ million) 9,910 11,142 3,280
Historical cost profit for the year............... ($ million) 8,010 11,870 5,008
Profit per ordinary share (diluted)............... (cents) 35.48 54.48 25.68
Dividends per ordinary share...................... (cents) 22.00 20.50 20.00
On January 1, 2001 the NGL business located in North America was
transferred from Refining and Marketing to Gas and Power. Comparative
information has been restated. For further information see Item 18 -- Financial
Statements -- Note 46.
During 2000 the Company acquired ARCO and Burmah Castrol plc (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: 2001 includes a full year; 2000 includes ARCO, Burmah Castrol and
the full consolidation of the European fuels business for varying parts of the
year; and 1999 does not include them at all.
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 and natural gas prices. The
higher turnover in 2000 compared with 1999 reflects a contribution from the 2000
portfolio changes, higher oil and natural gas prices in Exploration and
Production and higher natural gas volumes in Gas and Power.
As well as reporting net income (profit after inventory holding gains and
losses, calculated on a first-in, first-out basis), and after exceptional items
(as defined by UK GAAP: profits and losses on sale of fixed assets and
businesses or termination of operations and fundamental restructuring costs),
BP also reports results on a replacement cost basis (excluding inventory holding
gains and losses) and before exceptional items. In addition the Group discloses
the amount and nature of special items which are non-recurring charges and
credits that are not classified as exceptional items under UK GAAP. This is done
in order to provide a more comparable basis to the results and disclosures of US
companies and to indicate underlying trading performance undistorted by
significant restructuring, integration and other one-off charges and credits.
Special charges have been significant in 2001, 2000 and 1999. The discussion
below addresses each of these various measures and disclosures.
Replacement cost profit before exceptional items (which excludes inventory
holding gains and losses) was $9,880 million in 2001 compared with $11,214
million in 2000 and $5,330 million in 1999. In addition to exceptional items (as
identified under UK GAAP), these results are after special charges of $1,058
million ($821 million after tax) $1,994 million ($1,454 million after tax) and
$1,210 million ($876 million after tax), respectively; and depreciation and
amortization of $2,477 million, $1,535 million and nil respectively arising from
the fixed asset revaluation adjustment and goodwill consequent upon the ARCO and
Burmah Castrol acquisitions in 2000. The special items in 2001 primarily
comprised Castrol, Erdoelchemie and Solvay integration costs, additional
severance costs mainly related to former ARCO employees, and an impairment
charge for our partner-operated Venezuelan Lake Maracaibo operations. Also
included were costs related to rationalization of the European downstream
commercial business and of our Grangemouth site in Scotland. The special items
in 2000 primarily comprised ARCO, Vastar and Castrol integration costs,
rationalization costs following the BP and Amoco merger, a provision against the
Group's chemicals investment in Indonesia, environmental charges and asset
write-downs. The major components of the special charges in 1999 were
integration costs, costs associated with the restructuring programme,
write-downs in respect of asset impairments and project costs in respect of
process improvement and outsourcing.
65
The historical cost profit for 2001 was $8,010 million after inventory
holding losses of $1,900 million and including net exceptional gains of $535
million ($30 million after tax). For 2000, the historical cost profit was
$11,870 million, including inventory holding gains of $728 million and net
exceptional gains of $220 million ($72 million loss after tax). The historical
cost profit for 1999 was $5,008 million including inventory holding gains of
$1,728 million and after charging net exceptional losses of $2,280 million
($2,050 million after tax).
Years ended December 31,
------------------------
Special items 2001 2000 1999
----- ----- -----
($ million)
Restructuring, integration and rationalization costs
BP.................................................... 219 624 903
ARCO (including Vastar)............................... 208 633 --
Castrol............................................... 334 151 --
----- ----- -----
761 1,408 903
Provision against fixed asset investments................ -- 181 --
Asset write-downs........................................ 175 61 223
Litigation............................................... 60 63 60
Environmental charges.................................... -- 170 --
----- ----- -----
996 1,883 1,186
Interest-- bond redemption charges....................... 62 111 24
----- ----- -----
Total special items before tax........................... 1,058 1,994 1,210
===== ===== =====
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 have been weak since 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.
We achieved the targets for 2001 we had set in February 2001. Hydrocarbon
production grew by 5.5% and underlying performance improvements reached $2.0
billion before tax.
The $5.8 billion targeted reduction in the combined cost structure of the
enlarged group (against a 1998 baseline) was achieved in 2001.
The return on average capital employed (ROACE), based on replacement cost
profit before exceptional items, was 12% (13% after adjusting for special items)
compared with 16% (17% after adjusting for special items) in 2000 and 12% (13%
after adjusting for special items) in 1999. Owing to the significant
acquisitions that took place in 2000, the annual ROACE for 2000 has been
calculated as the average of the four discrete quarterly ROACEs.
Employee numbers increased slightly during 2001, as increases primarily
related to the acquisition of Bayer's 50% interest in Erdoelchemie, the Solvay
transaction and 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. Following integration
and rationalization activities, some 3,000 employees had left by the end of
2000. In 1999, following the merger of BP and Amoco, some 16,000 employees left
the Group through severance or outsourcing arrangements; a further 3,000
employees left in 2000. Of these, some 14,000 were based in the USA. The
reductions in 1999 and 2000 arose mainly in Houston, Texas; Chicago, Illinois;
and Cleveland and Warrensville, Ohio.
In November 2001, BP announced that it will restructure operations at the
Grangemouth refining and petrochemical complex in Scotland. The move is part of
a series of initiatives and investments to significantly improve the plant's
ability to compete in an increasingly difficult international refining and
chemicals environment. The reorganization will streamline Grangemouth's three
main activities - refining, petrochemicals and the Forties pipeline terminal -
into a single organization, designed to simplify site operations while
increasing reliability and efficiency. The restructuring is expected to result
in the reduction of up to 1,000 jobs at Grangemouth over the next two years.
Owing to the significant acquisitions that took place in 2000, in addition
to its reported results, BP is presenting pro forma results adjusted for special
items in order to enable shareholders to assess current performance in the
context of our past performance and against that of our competitors. The pro
forma result, adjusted for special items, has been derived from our UK GAAP
accounting information but is not in itself a recognized UK or US GAAP measure.
66
Pro forma
result
adjusted
for
Reconciliation of reported profit/loss to Acquisition Special special
pro forma result adjusted for special items Reported amortization (a) items (b) items
--------- ------------ ------- ---------
($ million)
Year ended December 31, 2001
Exploration and Production.......................... 12,417 1,759 322 14,498
Gas and Power....................................... 521 -- -- 521
Refining and Marketing.............................. 3,625 718 487 4,830
Chemicals........................................... 128 -- 114 242
Other businesses and corporate...................... (556) -- 73 (483)
------ ------ ------ ------
Replacement cost operating profit................... 16,135 2,477 996 19,608
Interest expense.................................... (1,670) -- 62 (1,608)
Taxation............................................ (4,512) -- (237) (4,749)
Minority shareholders' interest..................... (73) -- -- (73)
------ ------ ------ ------
Replacement cost profit before exceptional items.... 9,880 2,477 821 13,178
------ ====== ====== ------
per ordinary share (cents)....................... 44.03 58.73
====== ======
Year ended December 31, 2000 (c)
Exploration and Production.......................... 14,012 1,174 524 15,710
Gas and Power....................................... 571 -- -- 571
Refining and Marketing.............................. 3,523 440 595 4,558
Chemicals........................................... 760 -- 276 1,036
Other businesses and corporate...................... (1,110) -- 488 (622)
------ ------ ------ ------
Replacement cost operating profit................... 17,756 1,614 1,883 21,253
Interest expense.................................... (1,770) -- 111 (1,659)
Taxation............................................ (4,680) -- (540) (5,220)
Minority shareholders' interest..................... (92) (79) -- (171)
------ ------ ------ ------
Replacement cost profit before exceptional items.... 11,214 1,535 1,454 14,203
------ ====== ====== ------
per ordinary share (cents)....................... 51.82 65.63
====== ======
Year ended December 31, 1999 (c)
Exploration and Production.......................... 6,983 -- 299 7,282
Gas and Power....................................... 437 -- -- 437
Refining and Marketing.............................. 1,614 -- 242 1,856
Chemicals........................................... 686 -- 247 933
Other businesses and corporate...................... (826) -- 398 (428)
------ ------ ------ ------
Replacement cost operating profit................... 8,894 -- 1,186 10,080
Interest expense.................................... (1,316) -- 24 (1,292)
Taxation............................................ (2,110) -- (334) (2,444)
Minority shareholders' interest..................... (138) -- -- (138)
------ ------ ------ ------
Replacement cost profit before exceptional items.... 5,330 -- 876 6,206
------ ====== ====== ------
per ordinary share (cents)...................... 27.48 32.00
====== ======
----------
(a) Acquisition amortization refers to depreciation relating to the fixed asset
revaluation adjustment and amortization of goodwill consequent upon the
ARCO and Burmah Castrol acquisitions in 2000. There was no acquisition
amortization in 1999.
(b) The special items refer to non-recurring charges and credits reported in
the year.
(c) 1999 and 2000 have been restated to reflect the transfer of the NGL
business in North America from Refining and Marketing to Gas and Power.
67
Return on average capital employed (ROACE) 2001 2000 1999
------- ------- -------
($ million)
Replacement cost basis
Replacement cost profit before exceptional items............ 9,880 11,214 5,330
Interest.................................................... 1,670 1,770 1,316
Minority shareholders' interest............................. 73 92 138
------- ------- -------
11,623 13,076 6,784
======= ======= =======
Average Capital employed (a)................................ 95,801 86,214 58,107
ROACE....................................................... 12% 16% 12%
------- ------- -------
Pro forma and special items adjustments
Acquisition amortization.................................... 2,477 1,614 --
Special items (post tax).................................... 775 1,343 876
Average capital employed acquisition adjustment (b)......... 19,225 20,755 --
ROACE - Pro forma basis adjusted for special items (c)...... 19% 23% 13%
------- ------- -------
Historical cost basis
Historical cost profit after exceptional items.............. 8,010 11,870 5,008
Interest.................................................... 1,670 1,770 1,316
Minority shareholders' interest............................. 73 92 138
------- ------- -------
9,753 13,732 6,462
======= ======= =======
ROACE....................................................... 10% 17% 11%
----------
(a) 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 average capital employed for 2000 has been calculated as the
average of the four discrete quarters.
(b) Acquisition adjustment refers to the fixed asset revaluation adjustment and
goodwill consequent upon the ARCO and Burmah Castrol acquisitions.
(c) Based on the pro forma result adjusted for special items and capital
employed excluding the fixed asset revaluation adjustment and goodwill
resulting from the ARCO and Burmah Castrol acquisitions.
Capital expenditure and acquisitions (a) 2001 2000 1999
---- ----- -----
($ million)
Exploration and Production.................................. 8,627 6,383 4,194
Gas and Power............................................... 352 336 59
Refining and Marketing...................................... 2,386 2,369 1,571
Chemicals................................................... 1,446 1,585 1,215
Other businesses and corporate.............................. 389 498 204
------- ------- -------
Capital expenditure......................................... 13,200 11,171 7,243
Acquisitions for cash....................................... 924 8,936 102
------- ------- -------
14,124 20,107 7,345
Disposals................................................... (2,903) (4,559)(b) (2,441)
------- ------- -------
Net Investment.............................................. 11,221 15,548 4,904
======= ======= =======
----------
(a) 2000 Excludes $27,506 million for the ARCO acquisition.
(b) Excludes $6,803 million proceeds for the sale of ARCO assets.
Capital expenditure and acquisitions in 2001, 2000 and 1999 amounted to
$14,124 million, $47,613 million and $7,345 million, respectively. 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, 2.2% interests in PetroChina and
Sinopec, and ExxonMobil's aviation lubricants business. Excluding acquisitions,
capital expenditure for 2001 was $13,200 million compared with $11,171 million
for 2000, reflecting our growth programme. Capital expenditure excluding
acquisitions for 1999 was $7,243 million, reflecting reduced spending following
the BP and Amoco merger.
Capital expenditure in 2002 is likely to be around $12-13 billion. This is
consistent with historic levels of investment of the enlarged group. By focusing
on the better investment opportunities, this level of expenditure should permit
investment in Exploration and Production aimed at enabling its targeted
production growth of 5.5% in the medium term.
68
Dividends
The total dividends announced for 2001 were $4,935 million, against $4,625
million in 2000. Dividends per share for 2001 were 22.00 cents, compared with
20.50 cents per share in 2000, an increase of 7%. Following the adoption of FRS
19 in 2002, BP intends to continue to pay dividends in the future of around 60%
of its replacement cost profit before exceptional items after adjusting for
special items and acquisition amortization, adjusted to mid-cycle operating
conditions. Mid-cycle operating conditions reflect adjustments to prices,
margins, costs and capacity utilization to levels which we would expect on
average over the long term.
The company also intends to continue the operation of the Dividend
Reinvestment Plan (DRIP) for shareholders who wish to receive their dividend in
the form of shares rather than cash. The BP Direct Access Plan for US and
Canadian investors also includes a dividend reinvestment feature.
Consistent with our pledge to return surplus funds to shareholders, a total
of 154 million shares were repurchased and cancelled during 2001 at a cost of
$1.3 billion. The repurchased shares had a nominal value of $38.5 million and
represented 0.7% of ordinary shares in issue at the end of 2000. Since the
inception of the share repurchase programme in 2000, 376 million shares have
been repurchased and cancelled at a cost of $3.3 billion. No further repurchases
were made during the first quarter of 2002. BP will seek approval from
shareholders at the April 2002 annual general meeting to continue repurchasing
shares. The approval would allow shares to be bought back as and when the
Group's funding position permits.
Exceptional Items
For 2001, net exceptional gains, consisting of the profit or loss on sale
of fixed assets and businesses or termination of operations, were $535 million
before tax. 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, were partly offset by
losses mainly related to the sale or closure of certain chemicals activities.
Net exceptional gains were $220 million before tax in 2000, and related
mainly to disposal profits on the sale of the Group's common interest in Altura
Energy, the sale of the Alliance refinery and the divestment of exploration and
production interests in Trinidad, the UK and the USA, 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.
In 1999 the net exceptional losses of $2,280 million before tax comprised
restructuring costs of $1,943 million and a net loss on sales of fixed assets
and businesses or termination of operations of $337 million. The restructuring
costs arose from restructuring activity across the Group following the merger of
BP and Amoco at the end of 1998 and related predominantly to the Group's US
operations. The main areas of activity were the elimination of duplication in
the former BP and Amoco operations and ongoing restructuring to adapt to the
changing business environment, and some further outsourcing. The major elements
of the restructuring charges comprised employee severance costs ($1,212 million)
and provisions to cover future rental payments on surplus leasehold office
accommodation and other property ($297 million). Also included in the
restructuring charges were office closure costs, contract termination payments
and asset write-offs. The cash outflow for these restructuring charges during
1999 was $976 million and in 2000 was $446 million.
Sales of fixed assets and businesses or termination of operations in 1999
included the sale of distribution terminals and service stations in the USA
mandated by the Federal Trade Commission in connection with the BP and Amoco
merger. As part of the asset divestment programme, the Group disposed of its
Canadian oil properties, its interest in the Pedernales oil field in Venezuela
and certain chemicals operations.
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 $16,135 million in 2001, $17,756
million in 2000 and $8,894 million in 1999. The business results which follow
are presented on this basis.
69
Exploration and Production
Years ended December 31,
--------------------------
2001 2000 1999
---- ----- -----
Turnover....................................... ($ million) 28,229 30,942 19,133
Total replacement cost operating profit ($ million) 12,417 14,012 6,983
Results included:
Exploration expense.......................... ($ million) 480 599 548
Key statistics:
Average BP oil realizations (a).............. ($ per barrel) 22.50 26.63 16.74
Average West Texas Intermediate oil price.... ($ per barrel) 25.89 30.38 19.33
Average Brent oil price...................... ($ per barrel) 24.44 28.44 17.94
Average BP US natural gas realizations....... ($ per thousand cubic feet) 3.99 3.72 2.06
Average Henry Hub gas price (b).............. ($ per thousand cubic feet) 4.26 3.90 2.27
Crude oil production (net of royalties) (c).... (mb/d) 1,931 1,928 2,061
Natural gas production (net of royalties) (c).. (mmcf/d) 8,632 7,609 6,067
Total production (net of royalties) (c) (d).... (mboe/d) 3,419 3,240 3,107
----------
(a) Crude oil and natural gas liquids.
(b) Henry Hub First of Month Index.
(c) Includes BP's share of joint ventures and 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 2001 was $28,229 million compared with $30,942 million in 2000
and $19,133 million in 1999. 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
increase in turnover in 2000 over 1999 resulted from the acquisition of ARCO in
2000 and the effect of significantly higher oil and natural gas prices partly
offset by production lost through divestments.
The replacement cost operating profit for 2001 was $12,417 million compared
with $14,012 million in 2000 and $6,983 million in 1999. These results are after
charging special items of $322 million, $524 million and $299 million
respectively; and depreciation and amortization arising from the fixed asset
revaluation adjustment and goodwill consequent upon the ARCO acquisition of
$1,759 million, $1,174 million and nil respectively. 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, $60 million litigation and $10 million restructuring costs
related to the Grangemouth operating site in Scotland. The special charges in
2000 comprise mainly ARCO and Vastar integration costs. In 1999 special charges
were asset write-downs and integration and rationalization costs following the
BP and Amoco merger at the end of 1998.
Compared with a year ago, 2001 profit 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.
The increased profit for 2000 compared with 1999 reflected significantly
higher oil and natural gas prices, the ARCO acquisition and operational
improvements. Average realized oil prices were $9.89 a barrel higher than the
prior year and North American natural gas prices (i.e. our principal gas market)
were 76% above their 1999 level.
Total hydrocarbon production for 2001 increased 5.5%, in line with our
growth target. The reserve replacement ratio was 191% with 2.2 billion barrels
of oil equivalent booked through extensions, discoveries, revisions and improved
recovery. Replacement exceeded production for the eighth consecutive year.
Hydrocarbon production in 2000 was up 4% on 1999. Higher underlying
(excluding the net impact of acquisitions and divestments) natural gas
production and the ARCO acquisition more than offset lower oil production caused
by the disposal of our common interest in Altura Energy and other non-core
properties and the effect of a reduced capital spending programme in 1999.
70
In 2001, finding and development costs averaged $3.68 per barrel of oil
equivalent, compared with $3.29 in 2000 and $3.21 in 1999. Unit lifting costs
were $2.70 per barrel of oil equivalent compared with $2.60 in 2000 and $2.70 in
1999.
In support of continued growth, 2001 capital expenditure, at $8.9 billion
(including $0.3 billion of acquisitions), was nearly $2.5 billion higher than
last year. During 2001, the Mad Dog development (BP 60.5% and operator), in the
US Gulf of Mexico, was approved. Also, BP announced that the assets of
Chernogorneft have been returned to Sidanco (BP 11.2%). This completes the
restructuring of Sidanco with its debt substantially repaid and non-core assets
disposed of. Sidanco is now positioned as a low-cost Russian producer.
Our increased capital investment programme is beginning to bear fruit.
During 2001 oil began to flow from the Northstar field offshore Alaska, 250
miles north of the Arctic Circle. Other significant projects went into
production during the year, including the Crosby and Mica fields, both in 4,400
feet of water in the Gulf of Mexico, USA and the Girassol field, in 4,200 feet
of water offshore Angola. To continue the development of our natural gas
reserves in Trinidad, a new liquefied natural gas (LNG) processing plant is
planned to start up in 2002, and the engineering and design work on an
additional, larger plant has begun. The Horn Mountain, King's Peak and King
fields in the Gulf of Mexico are also scheduled for start-up in 2002.
We focused too on appraising and progressing our previous discoveries. In
2001, we sanctioned the Thunder Horse (previously known as Crazy Horse) and
Holstein fields and the Mardi Gras pipeline in the Gulf of Mexico, as well as
developments in Angola, Egypt, Alaska, Norway, Azerbaijan, Trinidad, Argentina
and West of Shetland, UK. Exploration successes during the year included
discoveries in Trinidad, Egypt and offshore Angola.
We entered the detailed engineering phase of the Baku-Tbilisi-Ceyhan oil
pipeline, scheduled to come on stream by 2005. This will link our growing oil
reserves in the Caspian to markets all over the world.
The effective application of the very best technology leads to higher
productivity and improved performance. Once new technologies have been proved
operationally, we apply them quickly and systematically across the Group to take
advantage of our global scale. For example, in 2001 we used time-lapse 3-D
seismic imaging in 19 North Sea fields to add new production and reserves, and
successfully tested a lightweight mooring buoy system that should reduce
drilling costs in deep water locations. We have also developed technologies to
reduce the cost of producing and transporting LNG.
Gas and Power
Years ended December 31,
--------------------------
2001 2000 1999
---- ----- -----
Turnover..........................................($ million) 39,208 21,013 8,073
Total replacement cost operating profit...........($ million) 521 571 437
Total natural gas sales volumes (a)...............(mmcf/d) 18,794 14,471 8,930
Total NGL sales volumes...........................(mb/d) 410 349 307
----------
(a) Includes marketing, trading and supply sales.
The Gas and Power business is responsible for BP's world-wide natural gas
marketing activities (although some long term natural gas sales contracts are
also included within Exploration and Production) and all business development
opportunities in natural gas, including gas-fired power generation.
On January 1, 2001, the NGL business located in North America was
transferred to Gas and Power from Refining and Marketing. Comparative
information has been restated.
71
Turnover has increased from $8,073 million in 1999 to $21,013 million in
2000 and to $39,208 million in 2001. The increase across the three years is
mainly attributable to higher sales volumes in the natural gas marketing and
trading business.
Replacement cost operating profit for 2001 was $521 million compared with
$571 million in 2000 and $437 million in 1999. 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 which have returned to more normal levels in 2001.
The higher profit in 2000 compared with 1999 reflected higher NGL margins
and higher natural gas sales volumes.
Gas sales increased from 8.9 billion cubic feet per day in 1999 to 14.5
billion cubic feet per day in 2000, and increased further to 18.8 billion cubic
feet per day in 2001.
Gas sales volumes were well ahead of our 2001 target, especially in North
America where we are one of the largest natural gas marketers. In Spain, as part
of our expansion into European natural gas, we consolidated our position as the
leading new entrant to the deregulated natural gas market.
In December 2001, Pertamina, our partner in the Tangguh, Indonesia natural
gas project, signed a Letter of Intent with the project's first potential
customer in the Philippines.
Capital expenditure and acquisitions for 2001 was $359 million compared
with $336 million in 2000 and included an additional investment in Green
Mountain Energy Company. Expenditure for 2000 included $125 million for the
first two instalments on two LNG ships and our initial investment in Green
Mountain Energy Company.
Refining and Marketing
Years ended December 31,
-----------------------
2001 2000 (a) 1999(a)
----- ----- -----
Turnover..................................($ million) 120,233 107,883 60,143
Total replacement cost operating profit...($ million) 3,625 3,523 1,614
Global Indicator Refining Margin (b)...... ($/bbl) 4.06 4.22 1.24
Refinery throughputs...................... (mb/d) 2,929 2,916 2,522
Total marketing sales .................... (mb/d) 3,797 3,420 2,879
----------
(a) Includes BP's share of the BP/Mobil European joint venture until August 1,
2000.
(b) The Global Indicator Refining Margin (GIM) is the average of seven regional
indicator margins weighted for BP's crude refining capacity in each region.
Each regional indicator margin is based on a single representative crude
with product yields characteristic of the typical level of upgrading
capacity.
On January 1, 2001, NGL business located in North America was transferred
to Gas and Power from Refining and Marketing. Comparative information has been
restated.
The increases in turnover between 1999 and 2000, and 2000 and 2001
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 2001 was $3,625 million compared
with $3,523 million in 2000 and $1,614 million in 1999. These results are after
special charges of $487 million, $595 million and $242 million respectively; and
depreciation and amortization arising from the fixed asset revaluation
adjustment and goodwill consequent upon the ARCO and Burmah Castrol acquisitions
of $718 million, $440 million and nil, respectively. Special charges in 2001
comprised Castrol integration costs, rationalization costs in the downstream
European commercial business, Grangemouth restructuring and 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. For 1999 special charges related principally to integration and
rationalization costs following the BP and Amoco merger and asset write-downs.
72
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 another 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, in line with our strategy, we completed the sale of
refineries at Mandan, North Dakota and Salt Lake City, Utah in the USA.
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.
We also achieved a unit cash cost reduction of 6% during the year, compared to
our target of 2.5%.
Compared with 1999, the 2000 result benefited from the 2000 portfolio
changes, cost reductions and a strong oil trading performance. In 2000, refining
margins were stronger in all regions than in 1999. Marketing margins came under
pressure due to the inability to pass through high product prices in competitive
markets.
The introduction of the BP Connect retail convenience store brand continued
throughout 2001, bringing the total number of new-format sites to 339, located
in the USA, Europe, Australia and New Zealand. Good progress was also made on
the rebranding and reimaging of former BP and Amoco retail sites with the new
colours and logo, with more than 4,600 sites being completed. We also grew our
market share in the Castrol lubricants business despite the difficult trading
conditions.
We took a very important step in Europe with the acquisition of 51% of Veba
Oil from the German utility E.ON. The deal was completed early in 2002,
finalizing one part of the arrangements originally announced in mid-2001. It
adds about 1.5 million new customers a day, making us the largest fuels retailer
in Germany and enhancing our capacity to supply clean fuels in central Europe.
Capital expenditure and acquisitions in 2001 was $2,415 million compared
with $8,693 million in 2000 and $1,571 million in 1999. Excluding acquisitions,
capital expenditure was $2,386 million compared with $2,369 million for the
previous year.
Chemicals
Years ended December 31,
--------------------------
2001 2000 1999
----- ----- -----
Turnover............................... ($ million) 11,515 11,247 9,392
Total replacement cost operating profit ($ million) 128 760 686
Chemicals Indicator Margin (a)......... ($/te) 108 (b) 126 (c) 114
Production volumes (d)................. (kte) 22,716 22,065 21,853
----------
(a) The Chemicals Indicator Margin (CIM) is a weighted average of
externally-based product margins. It is based on market data collected by
Chem Systems in their quarterly market analyses, then weighted based on
BP's product portfolio. While it does not cover our entire portfolio, it
includes a broad range of products. Amongst the products and businesses
covered in the CIM are the olefins and derivatives, the aromatics and
derivatives, linear alpha olefins, acetic acid, vinyl acetate monomer and
nitriles. Not included are fabrics and fibres, plastic fabrications, poly
alpha olefins, anhydrides, engineering polymers and carbon fibres,
speciality intermediates, and the remaining parts of the solvents and
acetyls businesses.
(b) Provisional. The data for the current year is based on eleven months of
actual data and one month of provisional data.
(c) Restated following review of product margins with Chem Systems.
(d) Includes BP share of joint ventures, associated undertakings and other
interests in production.
73
Turnover has increased from $9,392 million in 1999 to $11,247 million in
2000 and to $11,515 million in 2001. 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 from 1999 to 2000
reflected higher prices and higher production.
Replacement cost operating profit for 2001 was $128 million compared with
$760 million in 2000, special charges of $114 million, $276 million and $247
million respectively. Special charges for 2001 include Grangemouth restructuring
and costs related to Erdoelchemie and Solvay integration. In 2000 special
charges comprised provision against a chemicals investment in Indonesia, asset
write-downs and rationalization costs following the BP and Amoco merger. Special
charges in 1999 related mainly to integration and rationalization costs
following the BP and Amoco merger, asset write-downs and litigation costs.
The business environment for chemicals 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.
Production for the year was 22.7 million tonnes, up 3% on 2000 due to new
production and acquired assets.
Major restructuring continued throughout 2001, aimed at repositioning the
portfolio and lowering the cost base. In addition to the special charges above,
the 2001 results include further rationalization costs of $102 million.
Chemicals' demand was firm in the first half of 2000, but then weakened in
the final two quarters as the global economy slowed. Annual production rose 1%
to 22.1 million tonnes, despite operational difficulties at Grangemouth,
Scotland. Several initiatives to promote cost and capital efficiency helped
offset pressure on margins that were close to cyclical lows, as high oil and
natural gas prices boosted feedstock costs. The weakness of the euro added
pressure on margins in our European operations. Overall, productivity
improvements in 2000 more than offset the effects of the weaker environment.
In 2001, the strengthening of our chemicals business focused on building a
limited set of leading global positions. We took full ownership of Erdoelchemie
through acquisition of Bayer's 50% stake. A deal was completed with Solvay to
combine both companies' high-density polyethylene businesses. In addition,
Solvay's polypropylene business was transferred to BP and our non-core
engineering polymers business was transferred to Solvay. We also announced the
closure of a number of disadvantaged or non-core plants in the UK and USA.
Capital expenditure and acquisitions in 2001 was $1,926 million compared
with $1,585 million in 2000 and $1,215 million in 1999. Excluding acquisitions,
capital expenditure was $1,446 million, $1,585 million and $1,215 million
respectively.
Other Businesses and Corporate
Years ended December 31,
--------------------------
2001 2000 1999
----- ----- -----
Turnover............................... ($ million) 783 249 198
Replacement cost operating loss........ ($ million) (556) (1,110) (826)
Other Businesses and Corporate comprises Finance, BP Solar, our coal and
aluminium assets, our investments in PetroChina and Sinopec, interest income and
costs relating to corporate activities worldwide.
The net cost of Other Businesses and Corporate amounted to $556 million in
2001, $1,110 million in 2000 and $826 million in 1999. These net costs include
special charges of $73 million, $488 million and $398 million respectively.
Special charges in 2001 comprise additional severance charges mainly related to
former ARCO employees. For 2000 special charges were ARCO integration costs,
rationalization costs following the BP and Amoco merger and environmental
charges. Special charges in 1999 were principally integration and
rationalization costs following the BP and Amoco merger at the end of 1998.
BP Solar production and shipments for 2001 were 30% higher than in 2000,
which in turn were 31% higher than in 1999. A total of 55 megawatts (MW) of
solar panel generating capacity was sold in 2001 (2000, 42 MW and 1999, 32 MW).
During 2000, we purchased a 2.2% interest in PetroChina for $578 million
and a 2.2% interest in Sinopec for $416 million -- two of Asia's largest oil and
natural gas companies.
74
Interest Expense
Interest expense in 2001 was $1,670 million compared with $1,770 million in
2000 and $1,316 million in 1999. These amounts included special charges of $62
million, $111 million and $24 million respectively, arising from the early
redemption of bonds. After adjusting for these special charges, the decrease in
Group interest expense 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. After adjusting for special charges the
increase in interest expense between 1999 and 2000 reflects higher debt and
interest rates.
Taxation
The charge for corporate taxes in 2001 was $5,017 million, compared with
$4,972 million in 2000 and $1,880 million in 1999. The effective rate on
historical cost profit was 38% in 2001, 29% in 2000 and 27% in 1999. The higher
rate in 2001 compared to 2000 reflects the full year effect of the ARCO and
Burmah Castrol acquisition amortization charge (which is non-deductible for tax
purposes), together with non-deductible inventory holding losses (versus
inventory gains in 2000). The slightly higher rate in 2000 compared with 1999
reflects the non-deductible acquisition amortization charge in 2000 (but not in
1999), and reduced inventory holding gains, partly offset by low tax relief on
net exceptional items in 1999.
The effective rate on replacement cost profit before exceptional items was
31% compared with 29% in 2000 and 28% in 1999. 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). The increase in the rate in
2000 over 1999 was caused by the acquisition amortization charge in 2000 but not
in 1999, offset by lower timing benefits in 1999.
Outlook
The outlook for oil and gas prices is weaker than last year because of the
state of the global economy, a mild US winter and reduced jet fuel demand
following the events of September 11. The crude oil market looks broadly
balanced for the first half of 2002, if OPEC's latest round of quota reductions
offsets current demand weakness. Additional OPEC oil may be required in the
second half of the year to balance the market if demand improves in line with an
economic recovery. In the US natural gas market, a combination of recovery and
lower natural gas prices may boost demand during 2002, while lower drilling
activity could curtail growth in domestic production. Refining margins have been
poor so far in 2002 and may remain under pressure in the near term because of
weak oil product demand growth and relatively high inventories, especially in
the key US market. Retail margins are currently weaker owing to intense
competitive pressure. In chemicals, the near-term pattern of demand is likely to
be unchanged.
Environmental Expenditure
Years ended December 31,
--------------------------
2001 2000 1999
----- ----- -----
($ million)
Operating expenditure....................................... 575 653 414
Capital expenditure......................................... 423 298 246
Clean-ups................................................... 67 81 92
New provisions for environmental remediation................ 180 228 145
New provisions for decommissioning.......................... 156 139 80
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.
Environmental expenditure decreased in 2001 compared with 2000, reflecting
benefits realized from environmental programmes in prior years and the impact of
refinery disposals. Capital expenditure increased in 2001 compared with 2000 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. Further increases in
capital expenditure are expected in the near term. In addition to operating and
capital expenditures, we also create provisions for future environmental
remediation. Expenditure against such provisions is normally incurred in
subsequent periods and is not included in environmental operating expenditure
reported for such periods.
75
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 27. 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 periodically.
The Euro
As a result of the Treaty establishing the European Community, as amended
by the Treaty on European Union (the Treaty), European economic and monetary
union (EMU) has occurred for eleven out of the fifteen member countries of the
European Union (participating countries). The final stage of the Treaty began on
January 1, 1999.
For the participating countries, the fixed conversion rates between their
sovereign currencies (legacy currencies) prior to January 1, 1999 and the euro
have been established. The euro has been adopted as their common legal currency.
The legacy currencies remained legal tender as denominations of the euro between
January 1, 1999 and January 1, 2002 (the transition period).
The United Kingdom has not participated initially in EMU, but may do so at
a later time. The current policy of the UK government is that any decision to
join EMU will only be taken after a national referendum of the people.
By the end of 2001 all BP's business activities in the countries of the
euro zone were ready for full operation in euros following the official launch
of the notes and coins on January 1, 2002. The Company's commercial and
financial processes had been successfully adapted with effect from January 1,
1999 to allow its European operations to undertake transactions in the euro and
capture competitive advantage offered by the new currency. In common with
experience generally across Europe, the actual level of transactions in euro
which had previously been low rose significantly in the second half of 2001. The
costs associated with the euro programme are estimated at $100 million, of which
more than $90 million had been incurred by the end of the year. Of this amount,
$30 million has been capitalized.
76
LIQUIDITY AND CAPITAL RESOURCES
Cash Flow
Years ended December 31,
--------------------------
2001 2000 1999
----- ----- -----
($ million)
Net cash inflow from operating activities................... 22,409 20,416 10,290
Net cash inflow (outflow) .................................. 1,002 3,743 (82)
Net cash inflow for 2001 was $1,002 million, compared with an inflow of
$3,743 million in 2000. This is primarily driven by higher capital expenditure
and significantly lower divestment proceeds (2000 included proceeds from the
sale of the ARCO Alaska assets). The improvement in cash flow between 1999 and
2000 results from an almost doubling of operating cash flow partially offset by
higher tax payments and net cash outflows from capital expenditure, acquisitions
and disposals.
Net cash inflow from operating activities increased to $22,409 million in
2001 from $20,416 million in 2000 and $10,290 million in 1999. Lower income in
2001 compared with 2000 was more than compensated for by lower working capital
requirements and higher depreciation. Net cash inflow from operating activities
increased to $20,416 million in 2000 from $10,290 million in 1999. The main
factor in this improvement was the increased operating earnings.
Dividends from joint ventures and associated undertakings have decreased
from $1,168 million in 1999 to $1,039 million in 2000 and to $632 million in
2001. The principal factor underlying this decrease was the dissolution in
August, 2000 of the BP/Mobil European joint venture although in 2000 the decline
was partially offset by an increase in dividends from associated undertakings.
The net cash outflow from servicing of finance and returns from investments
was $948 million in 2001, $892 million in 2000 and $1,003 million in 1999. 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. The
net cash outflow from servicing of finance and returns from investments
decreased to $892 million from $1,003 million in 1999, principally because of
the lower payment of dividends to minority shareholders. The increase in
interest payments was largely offset by the increase in interest receipts.
Tax payments decreased to $4,660 million in 2001 from $6,198 million in
2000 reflecting lower profit in 2001 and additional taxes in 2000 related to the
FTC mandated disposal of ARCO's Alaskan operations. The increase in tax payments
from $1,260 million in 1999 to $6,189 million are attributable to higher profits
and the FTC mandated disposal in 2000.
Payments for capital expenditures on fixed assets net of proceeds from
sales of fixed assets, amounted to $9,849 million in 2001 compared with $7,072
million in 2000 and $5,385 million in 1999. The increase in 2001 over 2000 was
due to higher capital expenditure and lower disposal proceeds. Higher capital
expenditure in 2000 compared with 1999 was partly offset by higher disposal
proceeds. We are targeting annual investment in the $12-13 billion range over
the period 2001 to 2003 which is consistent with historic levels of investment
for the enlarged Group.
Acquisitions and disposals of businesses produced a net cash outflow of
$1,755 million 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. Acquisitions and disposals of
businesses produced a net cash inflow of $243 million in 1999. The increase in
disposal proceeds of $7,041 million between 1999 and 2000 was largely offset by
increased spend on acquisitions and investments in associated undertakings.
Overall net cash outflow for capital expenditure and acquisitions, net of
disposals, was $11,604 million (2000 $6,207 million and 1999 $5,142 million).
Dividend payments have increased to $4,827 million from $4,415 million in
2000 and $4,135 million in 1999. The increase in 2001 compared with 2000
reflects the impact of the higher dividend partly offset by share repurchases
during 2001. Higher dividend payments in 2000 compared with 1999 reflect the
increase in shares in issue as a result of the ARCO acquisition and the dividend
increase in the third quarter of 2000, partially offset by share repurchases
during 2000.
77
Financing the Group's Activities
The Group's principal commodity, oil, is priced internationally in US
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, 2001 amounted to $21,417 million (2000 $21,190 million) of which $9,090
million (2000 $6,418 million) was short term.
Net debt, that is debt less cash and liquid resources, was $19,609 million
at the end of 2001, an increase of $250 million over the year. The ratio of net
debt to net debt plus equity was 21% at the end of both 2001 and 2000. 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 26%. Our target range for this ratio for periods to December 31,
2001 was 20-30%.
The maturity profile and fixed/floating rate characteristics of the Group's
debt are described in Item 18 -- Financial Statements -- Note 25.
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, 2001 the Group's share of third party
borrowings of joint ventures and associated undertakings was $460 million and
$1,136 million respectively. These amounts are not reflected in the Group's debt
on the balance sheet.
The Company has issued guarantees under which amounts outstanding at
December 31, 2001 were $19,900 million (2000 $14,133 million), including $19,843
million (2000 $14,076 million) in respect of borrowings by its subsidiary
undertakings.
At December 31, 2001 contracts had been placed for authorized future
capital expenditure estimated at $4,712 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, 2001, the Group
had available undrawn committed borrowing facilities of $3,400 million ($3,450
million at December 31, 2000).
The following table summarizes the principal financial obligations which
are described in Item 18 -- Financial Statements -- Notes 25 and 32.
Payments due by period
----------------------------------------------------------
Within 1-2 2-3 3-4 4-5
Total 1 year years years years years Thereafter
----- ------ ----- ----- ----- ----- ----------
($ million)
Long-term borrowings............................ 12,751 1,993 1,460 641 1,566 651 6,440
Finance lease obligations....................... 3,648 97 159 165 173 177 2,877
Operating leases................................ 5,866 958 729 573 515 465 2,626
We have in place a European Debt Issuance Programme (DIP) and a US Shelf
Registration under each of which the Group may raise an aggregate of $6 billion
of debt for maturities of one month or longer. At March 26, 2002, the amount
drawn down against the DIP was $564 million, and $1,500 million under the US
Shelf Registration.
Commercial paper markets in the US and Europe are a primary source of
liquidity for the Group. At December 31, 2001 the outstanding commercial paper
amounted to $4,634 million (2000 $2,943 million).
BP believes that, taking into account the substantial amounts of undrawn
borrowing facilities available, the Group has sufficient working capital for
foreseeable requirements.
78
Liquidity Risk
Liquidity risk is the risk that suitable sources of funding for the Group's
business activities may not be available. The Group has long-term debt ratings
of Aa1 and AA+ assigned respectively by Moody's and Standard and Poor's. The
Group has access to a wide range of funding at competitive rates through the
capital markets and banks. It co-ordinates relationships with banks, borrowing
requirements, foreign exchange requirements and cash management centrally. The
Group believes it has access to sufficient funding and has also undrawn
committed borrowing facilities to meet currently foreseeable borrowing
requirements. At December 31, 2001, the Group had available undrawn committed
facilities of $3,400 million. These committed facilities, which are mainly with
a number of international banks, expire in 2002. The Group expects to renew the
facilities on an annual basis.
Credit Risk
Credit risk is the potential exposure of the Group to loss in the event of
non-performance by a counterparty. The credit risk arising from the Group's
normal commercial operations is controlled by individual operating units within
guidelines. In addition, as a result of its use of financial and commodity
instruments, including derivatives, to manage market risk, the Group has credit
exposures through its dealings in the financial and specialized oil and natural
gas markets. The Group controls the related credit risk by entering into
contracts only with highly credit-rated counterparties and through credit
approvals, limits and monitoring procedures, and does not usually require
collateral or other security. Counterparty credit validation, independent of the
dealers, is undertaken before contractual commitment. The Group has not
experienced material non-performance by any counterparty.
79
CRITICAL ACCOUNTING POLICIES AND NEW ACCOUNTING STANDARDS
UK GAAP Accounting Policies
The preparation of financial statements in conformity with UK generally
accepted accounting practices (UK GAAP) requires the Group 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 Company believes that the critical accounting policies and areas that
require the most significant judgments and estimates to be used in the
preparation of consolidated financial statements are in relation to oil and
natural gas reserves, depreciation and amounts provided, impairment, provisions
for deferred taxation, decommissioning, and environmental liabilities, and
pension and other postretirement benefits.
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, natural gas and
natural gas liquids 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.
Depreciation and Amounts Provided
The Group follows the successful efforts method of accounting for its oil
and gas activities. This accounting principle, among other things, requires 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).
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.
Impairment of Assets
Fixed assets and goodwill are assessed for impairment if there are events
or changes in circumstances which indicate that carrying values 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.
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 the
Group's best estimate of future oil and gas prices. 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.
Relatively modest amounts of impairment are routinely recognized in the
Group's results as a result of adverse changes in the recoverable reserves from
oil and natural gas fields, low plant utilization or reduced profitability.
However, 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
For accounting periods up to and including 2001, the Group provided
deferred taxation on a partial provision basis (see below for a discussion of
the new accounting standard, FRS 19, that has been adopted in 2002). This
requires estimates to be made of the extent to which timing differences are
expected to reverse in the foreseeable future.
80
Decommissioning and Environmental 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. Most of these removal obligations 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.
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.
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 will also
impact future results of operations.
Impact of New UK Accounting Standards
The Group has adopted Financial Reporting Standard No. 19 'Deferred Tax'
with effect from January 1, 2002. If this new standard had been applied to the
reported results for 2001, the tax charge for the year would have increased by
$1,358 million to $6,375 million. In addition, at December 31, 2001 there would
have been a reduction of $9,050 million in shareholders' interest.
In December 2000, the UK Accounting Standards Board issued Financial
Reporting Standard No. 17 'Retirement Benefits' ('FRS17'). This standard is
fully effective for accounting periods ending on or after June 22, 2003. Certain
of the disclosure requirements are effective for periods prior to 2003. 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
Company has not yet completed its evaluation of the impact of adopting FRS17 on
the Group's results of operations. It is believed that at December 31, 2001 the
impact on shareholders' interest would not be significant.
US GAAP
The consolidated financial statements of BP 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 43 of Notes to Financial Statements.
New US GAAP Accounting Standards adopted in 2001
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.
The Group's accounting policies under UK GAAP do not satisfy the criteria
for hedge accounting under SFAS 133. The Group does not intend to modify its
practice under UK GAAP.
81
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.
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 those derivative instruments, there was no impact
of adopting SFAS 133 on the Group's results of operations and financial
position, as adjusted to accord with 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) and a pre tax credit to other comprehensive income of $57
million ($37 million after tax). The net gain included in other comprehensive
income as of January 1, 2001 has been reclassified into earnings during 2001.
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. SFAS 133
requires these contracts to be marked to market. On the basis of SFAS 133
Implementation Issue C11, the cumulative effect of adopting SFAS 133 for these
derivatives resulted in a pre-tax charge to income, as adjusted to accord with
US GAAP, at July 1, 2001 of $530 million ($344 million after tax).
Because the Company does not intend to modify its accounting practice to
satisfy the criteria for hedge accounting under SFAS 133, the Group's results of
operations, as adjusted to accord with US GAAP, will not necessarily be
representative of the results it would report if US GAAP were used to prepare
the consolidated financial statements of the Group and the Group sought to meet
the hedge criteria of SFAS 133 and to apply hedge accounting.
Impact of New US Accounting Standards
In June 2001 the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No.141 'Business Combinations' (SFAS
141) and No. 142 'Goodwill and Other Intangible Assets' (SFAS 142). Under SFAS
141, the pooling of interest method of accounting is no longer permitted; the
purchase method must be used for all business combinations initiated after June
30, 2001. SFAS 142, which is effective for accounting periods beginning after
December 15, 2001, 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 will continue to be amortized over their estimated useful lives.
It is estimated that elimination of the requirement to amortize goodwill
would increase the Group's results of operations, as adjusted to accord with US
GAAP, by approximately $1,200 million for the year ended December 31, 2002.
Also in June 2001 the 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 provisions of SFAS 143 are similar to the accounting policy used by the
Group in preparing its financial statements under UK GAAP. The Company has not
yet determined the effect of adopting SFAS 143 on its results of operations and
shareholders' interest as adjusted to accord with US GAAP.
In August 2001, the FASB issued 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. SFAS 144 is effective for accounting periods beginning after
December 15, 2001.
The Company has not yet determined the effect of adopting SFAS 144 on its
results of operations and shareholders' interest as adjusted to accord with US
GAAP.
82
ITEM 6 -- DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
DIRECTORS AND SENIOR MANAGEMENT
The following lists the 18 directors on the board and the company
secretary.
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)
Dr J G S Buchanan............. Executive director (Chief financial October 1996
officer)
R F Chase..................... Executive director (Deputy group chief March 1992
executive)
W D Ford...................... Executive director January 2000
Dr B E Grote.................. Executive director August 2000
R L Olver..................... Executive director 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) December 1998
Sir Robert Wilson............. Non-executive director (a)(c)(d) July 1998
J C Hanratty.................. Secretary October 1994
----------
(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.
Mrs R S Block retired as a non-executive director on April 19, 2001; Dr C S
Gibson-Smith retired as an executive director on April 19, 2001; the Lord Wright
of Richmond retired as a non-executive director on April 30, 2001, and Mr R J
Ferris retired as a non-executive director on June 8, 2001. Dr D S Julius was
appointed a non-executive director with effect from November 29, 2001. Mr W D
Ford will retire as an executive director on March 31, 2002 and Sir Robert
Wilson will not be seeking re-election at the next annual general meeting and
will therefore retire as a non-executive director on April 18, 2002.
BP's articles of association require directors who have held office for
three years or more since they were appointed or re-elected to retire from
office at the Company's annual general meeting, together with directors
appointed by the board since the last annual general meeting. Retiring directors
may offer themselves for re-election. The Directors retiring and offering
themselves for re-election at this year's meeting are Mr J H Bryan,
Mr E B Davis Jr, Mr F A Maljers, Dr W E Massey, Mr P D Sutherland and
Mr M H Wilson. Dr D S Julius is standing for election by the shareholders.
The biographies of the directors and the secretary are set out below.
P D Sutherland, SC -- Peter Sutherland (55) 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 chairman of Goldman Sachs International
and a non-executive director of Telefonaktiebolaget LM Ericsson, Investor AB and
The Royal Bank of Scotland Group.
83
Sir Ian Prosser -- Sir Ian (58) 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, (54), 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.
He is also vice president and a member of the board of the Prince of Wales
Business Leaders Forum.
Dr J G S Buchanan -- John Buchanan (58), chief financial officer, was
appointed an executive director of BP in 1996. He is a non-executive director of
Boots.
R F Chase -- Rodney Chase (58), deputy group chief executive, was appointed
an executive director of BP in 1992. He is a non-executive director of Computer
Sciences Corporation and Diageo.
W D Ford -- Doug Ford (58), chief executive, downstream, was appointed an
executive director of BP in January 2000. Before the merger of BP and Amoco he
had been an executive vice president of Amoco since 1993. He is a non-executive
director of USG Corporation and a Trustee of the University of Notre Dame.
Dr B E Grote -- Byron Grote (53), chief executive, chemicals, was appointed
an executive director of BP in 2000.
R L Olver -- Dick Olver (55), chief executive, upstream, was appointed an
executive director of BP in 1998. He is a non-executive director of Reuters
Group.
J H Bryan -- John Bryan (65) 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 (57) joined Amoco's board in 1991. He
is chairman, 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 (52) joined BP's board in November
2001. She is a non-executive director of the Court of the Bank of England,
Lloyds TSB and Serco. 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 (66) joined BP's board in 1987. He is chairman
of Emerson Electric and is a non-executive director of Anheuser-Busch, Morgan
Stanley Dean Witter, SBC Communications and IBM.
F A Maljers -- Floris Maljers (68) 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 (63) 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. In 2001 he was
appointed by President George W. Bush to serve on the President's Council of
Advisors on Science and Technology.
H M P Miles, OBE -- Michael Miles (65) joined BP's board in 1994. He is
chairman of Johnson Matthey and a non-executive director of ING Baring Holdings
and Balfour Beatty.
Sir Robin Nicholson, FREng, FRS -- Sir Robin (67) joined BP's board in
1987. He is a non-executive director of Rolls-Royce.
M H Wilson -- Michael Wilson (64) joined Amoco's board in 1993. He is
president and chief executive officer of Brinson Canada and a non-executive
director of Manufacturers Life Insurance Company and UBS Asset Management.
Sir Robert Wilson, KCMG -- Sir Robert (58) joined BP's board in 1998. He is
chairman of Rio Tinto and a non-executive director of Diageo.
84
J C Hanratty -- Judith Hanratty (58) joined BP in London in 1986 and was
appointed company secretary in 1994. Miss Hanratty reports to the non-executive
Chairman and is not part of executive management. She provides senior governance
and legal counsel to the Board. She is a nominated member of the Council of
Lloyd's of London and of the Lloyd's Market Board. She is also a non-executive
director of Partnerships UK and Charles Taylor Consulting, and a member of the
Competition Commission and the Takeover Panel. A barrister, she is also the
chairman of the Commonwealth Institute and deputy chairman of the College of
Law.
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 belief in the need
to attract, motivate and retain world-class executive talent. The main
principles of the policy are:
-- Total reward levels should reflect the competitive global market and
the committee actively seeks independent advice on this.
-- The majority of the total reward is linked to achievement of demanding
performance targets as shown in the descriptions of the elements of
remuneration. By way of illustration, in 2001 over three-quarters of
the executive directors' remuneration was performance-based.
-- Executive directors should share the interests of shareholders in
making BP successful to the benefit of all shareholders. This is
achieved through setting robust performance targets based on measures
of shareholders' interests and through the committee's policy for
executive directors to hold a significant shareholding in the company,
currently equivalent to 5 times their base salary.
-- The performance targets in the Executive Directors' Long Term
Incentive Plan must encompass demanding comparisons of BP's
shareholder returns and earnings with those of other companies in its
own industry and in other sectors as well.
-- The committee continually assesses whether the reward structure is
achieving its objectives. In late 2001, it reviewed the existing
remuneration of all executive directors relative to a comparator group
of global companies. After taking independent external advice the
committee agreed that there should be no major changes in the
framework for total reward. In 2002 it will be reviewing long-term
incentive awards.
-- In 2002 base salaries for the executive directors will be increased by
less than 10%, in line with similar global companies.
-- All UK executive directors appointed after 1996 should hold a contract
of service with a maximum of a one-year period of notice.
Elements of remuneration
An increasing share of executive directors' pay is performance-related with
the majority now based on long-term performance. The more senior the executive,
the greater the proportion of 'at risk' remuneration.
There are three elements of executive remuneration: performance-based
components -- long-term; performance-based components -- short-term; and fixed
components. These are described in the following paragraphs.
Performance-based Components -- Long-term
The Executive Directors' Long Term Incentive Plan (EDLTIP) was adopted by
shareholders at the Annual General Meeting in April 2000 to provide long-term
incentives specifically for the executive directors.
EDLTIP has three elements:
Share Element
The share element compares BP's performance against 'oil majors' over three
years, on a rolling basis. This has been assessed in terms of a three-year
shareholder return against the market (SHRAM), return on average capital
employed (ROACE) and earnings per share (EPS) growth.
85
The committee reviews and approves annually the performance measures and
the comparator companies. The comparator group of companies used for the SHRAM
performance condition in the share element has been reduced so much by industry
consolidation that the committee has decided for the 2002-2004 Plan to change to
the FTSE All World Oil and Gas index weighted by market capitalization. The
committee is satisfied that this change does not make the performance targets of
the plan less demanding.
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. It is a condition for any such award that the individual holds
shares equivalent to at least five times base salary.
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.
Share Option Element
The share option element reflects BP's performance relative to a wider
selection of global companies. The committee will take 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.
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 2001.
Performance-based Components -- Short-term
Annual Bonus
The short-term performance-related component of executive directors'
remuneration consists of an annual bonus. The Remuneration Committee reviews and
sets bonus targets and level of eligibility annually. The target level is 100%
of base salary (except for Lord Browne who has a 110% target). There is a
stretch level of 150% of base salary for substantially exceeding targets.
Targets consist of a mix of demanding financial targets and other
leadership objectives covering areas such as people, safety, environment and
organization.
Fixed Components
Salary
Fixed sum, payable monthly in cash. Salaries are reviewed periodically in
line with global markets. The appropriate survey groups are defined and analysed
by a leading remuneration consultancy.
Pension
Executive directors are eligible to participate in the appropriate pension
schemes applicable in their home countries.
Benefits and Other Share Schemes
Executive directors are eligible to participate in regular employee benefit
plans, including health and life insurance and in all-employee share schemes and
savings plans as applicable in their home countries.
Resettlement Allowance
Expatriates may receive a resettlement allowance for a limited period.
86
2001 Remuneration for Executive Directors
The Group achieved a strong result in 2001, leading the industry in ROACE
and EPS growth. SHRAM results placed BP second in the group of comparable oil
companies. Cumulative savings on the combined cost structure of the enlarged
Group reached their target of $5.8 billion pre-tax, compared with a 1998 base.
There was excellent progress on leadership targets such as people, safety,
environment and organization.
Long term remuneration Annual remuneration
------------------------------------------ ---------------------------------------------------------------
Shares
awarded
Performance under
units granted 1999-2001 Share 2001 annual Benefits
Summary of under 2001-2003 share option performance and other 2001 2000
remuneration share element(a) element(b) grants(c) bonus Salary emoluments total total
--------------- --------- ------ ----------- ------ ---------- ----- -----
($ thousand)
The Lord Browne of Madingley 415,000 472,500 1,269,843 2,566 1,728 79 4,373 2,762
Dr J G S Buchanan........... 165,000 280,000 253,971 933 691 32 1,656 1,527
R F Chase................... 205,000 315,000 312,171 1,147 850 45 2,042 1,723
W D Ford.................... 170,000 175,000 261,036 972 720 496(d) 2,188 1,869
Dr B E Grote................ 155,000 175,000 241,092 898 665 301(d) 1,864 651
R L Olver................... 170,000 252,000 260,319 956 708 53 1,717 1,451
Director leaving the board in 2001
Dr C S Gibson-Smith......... -- 252,000 -- 773 497 444(e) 1,714 1,429
------------
The table above represents remuneration received by executive directors in
the 2001 financial year, with the exception of the 2001 annual bonus which
was earned in 2001 but paid in 2002. A conversion rate of (pound)1 = $1.44
has been used for 2001, (pound)1 = $1.51 for 2000.
(a) Performance units granted under the 2001-2003 LTPP are converted to shares
at the end of the performance period. Maximum of two shares per performance
unit.
(b) Gross award of shares. Sufficient shares are sold to pay for tax
applicable. Remaining shares are held in trust until 2005 when they are
released to the individual.
(c) Options granted in February 2001 have a grant price of (pound)5.67 per
share. Mr Ford and Dr Grote hold ADSs; the above numbers and prices reflect
calculated equivalents.
(d) Includes resettlement allowances for Mr Ford and Dr Grote of $440,000 and
$300,000 respectively.
(e) Includes pay in lieu of notice for Dr Gibson-Smith of $386,000.
87
Long-term performance-based components
Long Term Performance Plan (LTPP) and Share Element
The LTPP award for the 1999-2001 performance period was made in February
2002 based on results achieved. The shares then have a minimum three years'
retention in trust and no shares will be released until the director has a
personal holding of BP shares equivalent to five times base salary.
Performance period of Plan 1998-2000 1999-2001 2000-2002 2001-2003
--------------- --------------- --------------- ---------------
Year of award 2001 2002 2003 2004
--------------- --------------- --------------- ---------------
Performance measures (a) SHRAM, EPS SHRAM, EPS SHRAM, EPS
SHRAM and ROACE and ROACE and ROACE
--------------- --------------- --------------- ---------------
Actual award Expected award (c) Maximum Maximum
award award
(shares) (value)(b) (shares) (value)(d) (shares) (shares)
------ ------ ------ ------ ------ ------
($ thousand) ($ thousand)
Current executive directors
The Lord Browne of Madingley. 532,600 4,357 472,500 3,708 560,000 830,000
Dr J G S Buchanan............ -- (e) -- 280,000 2,197 308,000 330,000
R F Chase.................... 339,000 2,773 315,000 2,472 348,000 410,000
W D Ford..................... -- -- 175,000 1,373 264,000 340,000
Dr B E Grote................. 247,000 2,020 175,000 1,373 170,000 310,000
R L Olver.................... 297,400 2,433 252,000 1,978 294,000 340,000
Former executive directors
Dr C S Gibson-Smith.......... 297,400 2,433 252,000 1,978 280,000 --
B K Sanderson................ 339,000 2,773 280,000 2,197 -- --
H L Fuller................... -- -- 472,500 3,708 -- --
----------
(a) Shareholder return against the market (SHRAM), earnings per share (EPS),
return on average capital employed (ROACE). In order to assess current
performance on a consistent basis with past performance and a basis
comparable with major competitors, EPS and ROACE in 2000 and going forward
will be calculated on a pro forma basis, adjusted for special items. The
pro forma basis excludes acquisition amortization and for operating capital
employed it excludes the fixed asset revaluation adjustment and goodwill
resulting from the ARCO and Burmah Castrol acquisitions. Acquisition
amortization is the depreciation relating to the fixed asset revaluation
adjustment and amortization of goodwill consequent upon these acquisitions.
Special items are non-recurring charges and credits that are not classified
as exceptional under UK GAAP.
(b) Based on average market price on date of award ((pound)5.68/$8.18
at(pound)1 = $1.44).
(c) The Remuneration Committee's current expectation based on assessed
performance and other terms of the Plan. The calculations for the 1999-2001
Plan include the share split.
(d) Based on mid-market price of BP shares on February 12, 2002
((pound)5.45/$7.85 at(pound)1 = $1.44).
(e) Dr Buchanan elected to defer until 2004 the determination of whether an
award should be made for this period.
For the 1998-2000 LTPP BP's performance was assessed in terms of three-year
shareholder return against the market (SHRAM) in relation to the following
companies: Chevron, ExxonMobil, Shell and Texaco. BP came first in the 1998-2000
Plan, and the Remuneration Committee made the maximum award of shares to
executive directors in 2001.
For the 1999-2001 Plan BP's SHRAM again exceeded ChevronTexaco, ExxonMobil
and TotalFinaElf, but came second to Shell.
The Remuneration Committee has also considered profitability and growth
targets for the 1999-2001 Plan, i.e. return on average capital employed (ROACE)
and earnings per share (EPS) growth. On both measures BP came first in assessing
performance against the same oil companies.
Based on an initial performance assessment of 175 points out of 200, the
committee expects to make an award of shares to executive directors as set out
in the 1999-2001 column of the above LTPP table.
Share Option Element and Other Option Schemes
Option grants in 2001 were made taking into consideration the ranking of
the Company's total shareholder return (TSR) against the TSR of the FTSE Global
100 group of companies over the three-year period from January 1, 1998. Options
granted vest over three years (one-third each after one, two and three years
respectively) and have a life of seven years after grant. Executive directors
who retire after January 1, 2002 may retain vested options for this period.
88
Market
At At price at Date from
Option Jan 1, Dec 31, Option date of which first
type 2001 Granted Exercised 2001 price exercise exercisable Expiry date
------ -------- ------- --------- ------- ------ --------- ----------- -----------
The Lord Brown of Madingley SAYE 5,968 -- -- 5,968 (pound)2.89 -- Sept 1, 02 Feb 28, 03
EDLTIP 408,522 -- -- 408,522 (pound)5.99 -- May 15, 01 May 15, 07
EDLTIP -- 1,269,843 -- 1,269,843 (pound)5.67 -- Feb 19, 02 Feb 19, 08
Dr J G S Buchanan.......... SAYE 2,980 -- 2,980 -- (pound)2.32 (pound)5.60 Sept 1, 01 Feb 28, 02
SAYE 1,856 -- -- 1,856 (pound)3.72 -- Sept 1, 03 Feb 28, 04
SAYE 750 -- -- 750 (pound)4.50 -- Sept 1, 04 Feb 28, 05
SAYE -- 1,320 -- 1,320 (pound)5.11 -- Sept 1, 06 Feb 28, 07
EDLTIP 75,189 -- -- 75,189 (pound)5.99 -- May 15, 01 May 15, 07
EDLTIP -- 253,971 -- 253,971 (pound)5.67 -- Feb 19, 02 Feb 19, 08
R F Chase................. SAYE 3,388 -- -- 3,388 (pound)4.98 -- Sept 1, 05 Feb 28, 06
EDLTIP 85,215 -- -- 85,215 (pound)5.99 -- May 15, 01 May 15, 07
EDLTIP -- 312,171 -- 312,171 (pound)5.67 -- Feb 19, 02 Feb 19, 08
W D Ford(a)............... 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
EDLTIP -- 43,506 -- 43,506 $49.65 -- Feb 19, 02 Feb 19, 08
Dr B E Grote(a)........... SAR 40,000 -- -- 40,000 $13.63 -- Mar 23, 93 Mar 23, 03
SAR 40,800 -- -- 40,800 $16.63 -- Mar 25, 94 Mar 25, 04
SAR 35,600 -- -- 35,600 $19.16 -- Feb 28, 95 Feb 28, 05
SAR 35,200 -- -- 35,200 $25.27 -- Mar 6, 96 Mar 6, 06
SAR 40,000 -- -- 40,000 $33.34 -- Feb 28, 97 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
EDLTIP -- 40,182 -- 40,182 $49.65 -- Feb 19, 02 Feb 19, 08
R L Olver................. SAYE 4,470 -- 4,470 -- (pound)2.32 (pound)5.29 Sept 1, 01 Feb 28, 02
SAYE 2,386 -- -- 2,386 (pound)2.89 -- Sept 1, 02 Feb 28, 03
SAYE -- 1,137 -- 1,137 (pound)5.11 -- Sept 1, 03 Feb 28, 04
EDLTIP 71,847 -- -- 71,847 (pound)5.99 -- May 15, 01 May 15, 07
EDLTIP -- 260,319 -- 260,319 (pound)5.67 -- Feb 19, 02 Feb 19, 08
Director leaving the board in 2001
Dr C S Gibson-Smith....... SAYE 2,154 -- -- 2,154(b) (pound)4.50
EDLTIP 68,505 -- -- 68,505(b) (pound)5.99
----------
EDLTIP -- Executive Directors' Long Term Incentive Plan adopted by
shareholders in April 2000 as described under Compensation --
Performance-based Components -- Long-term.
BPA -- BP share option plan which applied to US executive directors
prior to the adoption of the EDLTIP.
NRSO -- Amoco Non-Restricted Stock Option which applied to Mr Ford as
an employee of Amoco.
SAR -- Stock Appreciation Rights under BP America Inc. Share
Appreciation Plan.
SAYE -- Save as You Earn employee share option scheme.
(a) Numbers shown are ADSs under option. One ADS is equivalent to six ordinary
shares.
(b) At retirement on April 19, 2001.
Short-term performance-based components
Executive directors' annual bonus awards for 2001 were based on a mix of
financial targets and leadership objectives established at the beginning of the
year. Assessment of all the targets showed that, compared with a target
performance of 100 points, 135 points were achieved, resulting in bonus awards
as shown in the summary of remuneration under the heading Compensation --
Elements of Remuneration.
Salaries
Each year the committee receives independent advice on competitive global
salary markets for the group chief executive and for the other executive
directors. Taking into account this advice and the fact that base salaries had
not previously been increased since October 1999, the committee decided to
increase Lord Browne's salary by 47% and the other executive directors' salaries
by an average of 15% for 2001.
89
Pensions
Additional Additional
pension earned pension earned
Accrued during the during the
Service benefit at year ended year ended
Pension entitlement-- at December 31, December 31, December 31, December 31,
UK executive directors 2001 2001 2001 (b) 2000 (b)
------------- ------------- ------------- -------------
($ thousand)(a) ($ thousand)(a) ($ thousand)(a)
The Lord Browne of Madingley 35 yrs 1,152 346 (15)
Dr J G S Buchanan........... 32 yrs 461 29 15
R F Chase................... 37 yrs 566 62 (9)
Dr C S Gibson-Smith (c)..... 30 yrs 420 48 14
R L Olver................... 28 yrs 470 68 14
----------
(a) An exchange rate of(pound)1 = $1.44 has been used for 2001,(pound)1 = $1.51
for 2000.
(b) Excludes the impact of inflation.
(c) Figures shown at date ceased being a director (April 19, 2001).
UK directors are members of the BP Pension Scheme (the Scheme). The Scheme
offers Inland Revenue-approved retirement benefits based on final salary. It is
the principal section of the BP Pension Fund (the Fund), the latter being set up
under trust deed. Company contributions to the Fund are made on the advice of
the actuary appointed by the Trustee. No company contributions were made during
2001.
Scheme members' core benefits are non-contributory. They include a pension
accrual of 1/60th of basic salary for each year of service, subject to a maximum
of two-thirds of final basic salary; a lump-sum death-in-service benefit of
three times salary; and a dependant's benefit of two-thirds of the member's
pension. The Scheme pension is not integrated with state pension benefits.
Normal retirement age is 60, but Scheme members who have 30 or more years'
pensionable service at age 55 can elect to retire early without an actuarial
reduction being applied to their pension.
Pensions payable from the Fund are guaranteed to be increased annually in
line with changes to the Retail Prices Index, up to a maximum of 5% a year.
Directors accrue pension on a non-contributory basis at the enhanced rate
of 2/60ths of their final salary for each year of service as executive directors
(up to the same two-thirds limit). None of the directors is affected by the
pensionable earnings cap.
Additional Additional
pension earned pension earned
Accrued during the during the
Service benefit at year ended year ended
Pension entitlement-- at December 31, December 31, December 31, December 31,
US executive directors 2001 2001 2001 2000
------------- ------------- ------------- -------------
($ thousand) ($ thousand) ($ thousand)
W D Ford.................... 31 yrs 504(a) 128(a) 67
Dr B E Grote................ 22 yrs 83 14 10
----------
(a) Includes a temporary annuity of $7,123 which is payable until age 62.
US directors participate in the BP Retirement Accumulation Plan (the US
Plan). Under the US Plan, the amount of the annuity they are eligible to receive
on a single-life basis is determined using a cash balance formula. The US Plan
was established in 2000; it superseded earlier Group pension and cash balance
plans. However, those employees who satisfied certain age and service conditions
at the date of transition to the US Plan were provided with minimum benefits
equal to those they would have earned under their previous pension arrangements.
In line with US tax regulations, benefits are provided through a combination of
tax qualified and restoration/non-qualified plans, as appropriate.
Under these 'grandfathering' arrangements, the annuity benefit formula
(which includes a percentage of US Social Security benefits) is calculated at
1.67% times years of participation times average annual earnings. These earnings
are determined by taking separately the three highest consecutive calendar
years' earnings from salary and the three highest consecutive calendar years'
bonus awards during the 10 years preceding retirement. The maximum annuity is
60% of such average earnings.
90
Normal pensionable age is 65. No actuarial reduction is applied to the
pension if it is paid from age 60; however, a reduction of 5% a year is applied
if paid between ages 50 and 59.
Mr Ford is subject to the 'grandfathering' arrangements and his figures
have been disclosed on this basis.
Dr Grote is not subject to the 'grandfathering' arrangements. His benefit
is determined by the cash balance formula, under which each year of service
accrues a monetary credit in a current account. The credit is based on a sliding
scale, referencing age and service, and is subject to a minimum of 4% and a
maximum of 11% of eligible pay. The account balance earns interest on a monthly
basis.
Executive Directors' Shareholdings
Change in
At directors'
January 1, 2001 interests from
Executive directors' interests in At or on December 31, 2001
BP ordinary shares or calculated December 31, 2001 appointment to March 26, 2002
equivalents ----------------- --------------- -----------------
Current directors
The Lord Browne of Madingley........... 1,392,184(a) 1,069,445(a) 283,500
Dr J G S Buchanan...................... 723,149 721,312 168,242
R F Chase.............................. 794,745 709,325 189,204
W D Ford............................... 333,139(b) 311,358(b) 170,687
Dr B E Grote........................... 595,845(b) 431,598(b) 105,000
R L Olver.............................. 585,852 421,910 151,526
At
On retirement January 1, 2001
-------------- ---------------
Director leaving the board in 2001
Dr C S Gibson-Smith.................... 671,812(c) 491,395
----------
(a) Includes 50,368 ordinary shares held as ADSs throughout 2001. One ADS is
equivalent to six ordinary shares.
(b) Held as ADSs.
(c) On retirement on April 19, 2001.
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.
By operation of law, the executive directors who participate in certain
all-employee SAYE option schemes are regarded as having an interest in such
shares of the company held from time to time by BP QUEST Company Limited, which
facilitates the operation of such schemes. The individual interests of executive
directors in share-based remuneration are set out on page 87 of this report.
Service Contracts
All executive directors appointed since 1996 hold a contract of service
which includes a period of notice of one year or less, except Mr Ford. Lord
Browne and Mr Chase were appointed prior to 1996 and have contracts with a
two-year notice period. The board does not consider it in shareholders'
interests to renegotiate these contracts.
Mr Ford has resigned from the board of BP p.l.c. with effect from March 31,
2002, at which time his secondment will end. His underlying US employment
agreement with BP Corporation North America has a two-month notice period. If
his contract is terminated by BP Corporation North America without cause, it is
required to pay him $1 million per annum (pro rated for part years) for each
year between the date of severance and January 21, 2004.
Remuneration of Non-Executive Directors
The articles of association provide that the remuneration paid to
non-executive directors is to be determined by the board within the limits set
by the shareholders. Non-executive directors do not have service contracts with
the Company. Their fees are fixed and paid in pounds sterling. For conformity,
these are also reported in US dollars.
91
During 2001, the non-executive chairman received a fee of (pound) 280,000
($403,000) and the non-executive deputy chairman a fee of (pound) 85,000
($122,000). The non-executive directors received an annual fee of (pound) 45,000
($65,000), plus an allowance of (pound) 3,000 ($4,000) for each occasion on
which a director travels across the Atlantic for a board meeting or committee
meeting. During 2001, the board met nine times, six times in the UK and three
times in the USA. Committee meetings are held in conjunction with board meetings
whenever feasible. Details of individual fees and allowances are set out in the
table below.
Year ended Year ended
Current directors December 31, 2001(a) December 31, 2000(b)
----------------- -----------------
(thousands)
(pound) $ (pound) $
J H Bryan.................................. 57 82 58 88
E B Davis, Jr.............................. 57 82 58 88
Dr D S Julius.............................. 4 6 -- --
C F Knight................................. 54 78 55 83
F A Maljers................................ 54 78 43 65
Dr W E Massey.............................. 65 94 55 83
H M P Miles (c)............................ 54 78 46 69
Sir Robin Nicholson (d).................... 57 83 46 69
Sir Ian Prosser............................ 85 122 80 121
PD Sutherland.............................. 280 403 160 242(e)
M H Wilson................................. 60 86 58 88
Sir Robert Wilson.......................... 51 73 46 69
------ ------ ------ ------
878 1,265 705 1,065
====== ====== ====== ======
Directors leaving the board in 2001 (f)
R S Block.................................. 17 24 49 74
R J Ferris................................. 32 45 52 79
The Lord Wright of Richmond (g)............ 20 28 46 69
----------
(a) Sterling payments converted at the average 2001 exchange rate of(pound)1 =
$1.44.
(b) Sterling payments converted at the average 2000 exchange rate of(pound)1 =
$1.51.
(c) Also received (pound) 300 ($432) for serving as a director of BP Pension
Trustees Limited in 2001.
(d) Also received (pound) 20,000 per year ($30,200 at 2000 rate; $28,800 at
2001 rate) for serving on the Technology Advisory Council.
(e) Also received other benefits of (pound) 1,518 ($2,292 at 2000 rate).
(f) In addition to their remuneration, certain payments in lieu of pension were
made or released to non-executive directors leaving the board during 2001,
totalling (pound) 487,853 ($702,508). These included meeting obligations
entered into by Amoco Corporation with respect to former Amoco
non-executive directors. Details of these are given in Item 18 -- Financial
Statements -- Note 35.
(g) Also received (pound) 1,200 ($1,812) for serving as a director of BP
Pension Trustees Limited in 2000 and (pound) 300 ($432) in 2001.
92
BOARD PRACTICES
Directors' Terms of Office Period during which the
director has served in
Date of expiration of this office (from
current term of office appointment to April 2002)
---------------------- -------------------------
The Lord Browne of Madingley.............. April 2004 10 years 7 months
J H Bryan (a).............................. April 2002 3 years 4 months
Dr J G S Buchanan.......................... April 2003 5 years 7 months
Mr R F Chase............................... April 2003 10 years 1 month
E B Davis, Jr (a).......................... April 2002 3 years 4 months
W D Ford................................... Retires March 2002 2 years 4 months
Dr B E Grote............................... April 2004 1 year 9 months
Dr D S Julius.............................. April 2002 5 months
C F Knight................................. April 2003 14 years 7 months
F A Maljers (a)............................ April 2002 3 years 4 months
Dr W E Massey (a).......................... April 2002 3 years 4 months
H M P Miles................................ April 2004 7 years 11 months
Sir Robin Nicholson....................... April 2004 14 years 7 months
R L Olver.................................. April 2004 4 years 4 months
Sir Ian Prosser........................... April 2004 5 years
P D Sutherland............................. April 2002 6 years 8 months
M H Wilson (a)............................. April 2002 3 years 4 months
Sir Robert Wilson......................... Retires April 2002 3 years 9 months
----------
(a) Does not include service on the board of Amoco Corporation.
Directors' Service Contracts Providing for Benefits upon Termination of
Employment
Non-executive directors do not have service contracts with the Company;
they are not employees of the Company. Non-executive directors are not entitled
to any benefits on termination of office. Executive directors are employees of
the Company or one of its subsidiaries under a variety of contracts of service.
The standard contract of service for executive directors provides for one year's
notice to be given of termination of the contract or payment of one year's
salary in lieu of notice. There are three exceptions to this standard contract:
The Lord Browne of Madingley, Mr Chase and Mr Ford. Lord Browne and Mr Chase
have contracts that provide for two year's notice of termination. Mr Ford has
resigned from the board of BP p.l.c. with effect from March 31, 2002, at which
time his secondment will end. His underlying US employment agreement with BP
Corporation North America has a two-month notice period. If his contract is
terminated by BP Corporation North America without cause, it is required to pay
him $1 million per annum (pro rated for part years) for each year between the
date of severance and January 21, 2004.
Corporate Governance Statement
General
The board's governance policies (adopted in 1997) 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 to 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 2001 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 UK Combined
Code on Corporate Governance. Finally, the company secretary reports to the
non-executive chairman and is not part of the executive management.
93
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 2001 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 Form 20-F filed annually with the US Securities
and Exchange Commission, quarterly announcements made through stock exchanges on
which the 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 chairmen of the Audit Committee, Remuneration Committee
and all other committee chairmen were present at the 2001 annual general meeting
to answer questions along with the chairman. Shareholder-requisitioned
resolutions have been moved before the last two annual general meetings. 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. In addition to the e-voting facility available to shareholders
for the first time in 2001, presentations given at appropriate intervals to
representatives of the investment community in both the UK and the USA are
available simultaneously to all shareholders by live internet broadcast or open
conference call.
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) -- organization and
succession planning and overall performance assessment.
-- Audit Committee (four to six non-executive directors) -- monitoring all
reporting, accounting, control and the financial aspects of the executive
management's activities. Further details are given below.
-- Ethics and Environment Assurance Committee (four to six non-executive
directors) -- monitoring the non-financial aspects of the executive
management's activities.
-- Remuneration Committee (four to six non-executive directors) -- determining
performance contracts and targets and the structure of the rewards for the
group chief executive and the executive directors. Further details are set
forth below.
In addition, there is a Nomination Committee, which comprises the
non-executive chairman, the group chief executive and three non-executive
directors selected from time to time as required.
The qualification for membership of the board includes a requirement that
non-executive directors be free from any relationship with the executive
management of the company that could materially interfere with the exercise of
their independent judgement. In the board's view, all non-executive directors
fulfil this requirement.
94
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 shareholders' interest in the Group, not to eliminate the possibility
of any adverse outcomes for shareholders.
Board/Executive Relationship
The board/executive relationship policy sets out how the board delegates
authority to the group chief executive and the extent of that authority. In its
goals policy, the board states the long-term outcome it expects the group chief
executive to deliver. The restrictions on the manner in which the group chief
executive may achieve the required results are set out in the executive
limitations policy, which addresses ethics, health, safety, the environment,
financial distress, internal control, risk preferences, treatment of employees
and political considerations. On all these matters, the board's role is to set
general policy and to monitor the implementation of 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. The board reviews this report at each meeting.
The board/executive relationship policy also sets out how the group chief
executive's performance will be monitored and recognizes that, in the multitude
of changing circumstances, judgement is always involved. The group chief
executive is obliged through dialogue and systematic review to discuss with the
board all material matters currently or prospectively affecting the company and
its performance and all strategic projects or developments. This specifically
includes any materially under-performing business activities and actions that
breach the executive limitations policy. 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 six non-executive directors: Sir Ian Prosser
(Chairman), Mr Bryan, Mr Davis Jr, Mr Miles, Mr Wilson and Sir Robert 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 tasks given to the Audit Committee by the Board Governance Policies
are:
-- To monitor systematically and obtain assurance that the legally
required standards of disclosure are being fully and fairly observed.
-- To review all prospectuses, information and offering memoranda and
other documents to be placed before shareholders and make
recommendations to the board about their adoption and publication.
-- To review all annual, quarterly and similar reports to shareholders
and make recommendations to the board about their adoption and
publication.
-- To monitor systematically and obtain assurance that the Executive
Limitations set out in the Board Governance Policies relating to
financial matters are being observed.
The Committee met seven times in 2001.
95
Remuneration Committee
The Remuneration Committee decides the remuneration policy and sets the
terms of engagement and total rewards of the executive directors. The committee
agrees each executive director's service contract, salary, targets and bonus
scheme, and the grants of options and performance units under the Executive
Directors' Long Term Incentive Plan.
Its members are all independent non-executive directors. The current
membership is Sir Robin Nicholson (chairman), Mr Knight, Sir Ian Prosser, Mr
Davis and Dr Julius. During the year Mrs Block, Mr Ferris and the Lord Wright of
Richmond retired. Like other directors, each member of the committee is subject
to periodic 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. The committee
consults the group chief executive on matters relating to other executive
directors who report to him. He is not present when matters affecting his own
remuneration are considered. The chairman of the board also attends meetings
when appropriate.
The committee is serviced independently of the executive management and
actively seeks advice from external professional consultants. In its
constitution and operation it complies with the 'Principles of Good Governance
and Code of Best Practice' set out by the Listing Rules of the Financial
Services Authority (FSA). Ernst & Young LLP have confirmed that the scope of
their report on the accounts covers the disclosures contained in this report
that are specified for audit by the Listing Rules.
EMPLOYEES
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
Number of employees at December 31,
2001
Exploration and Production............. 3,700 800 5,500 6,550 16,550
Gas and Power.......................... 600 150 600 600 1,950
Refining and Marketing ................ 10,500 16,250 26,600 11,250 64,600
Chemicals.............................. 3,450 6,250 6,700 5,550 21,950
Other businesses and corporate......... 1,400 550 2,100 1,050 5,100
-------- -------- -------- -------- --------
19,650 24,000 41,500 25,000 110,150
======== ======== ======== ======== ========
2000
Exploration and Production............. 3,300 700 5,900 6,100 16,000
Gas and Power.......................... 500 100 700 300 1,600
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......... 1,300 400 2,500 700 4,900
-------- -------- -------- -------- --------
18,900 22,500 44,000 21,800 107,200
======== ======== ======== ======== ========
1999
Exploration and Production............. 3,700 1,150 2,800 4,850 12,500
Gas and Power.......................... 450 50 600 300 1,400
Refining and Marketing ................ 9,000 11,150 17,500 7,000 44,650
Chemicals.............................. 3,950 4,700 8,100 1,950 18,700
Other businesses and corporate......... 1,150 300 1,150 550 3,150
-------- -------- -------- -------- --------
18,250 17,350 30,150 14,650 80,400
======== ======== ======== ======== ========
Following the merger of BP and Amoco on December 31, 1998, some 19,000
employees have left the Group through severance or outsourcing arrangements. Of
this total approximately 16,000 employees left in 1999. The acquisition of ARCO
and Burmah Castrol during 2000 brought approximately 25,000 additional employees
to the Group, of which some 3,000 have left through integration and
rationalization activities. Employee numbers increased slightly during 2001, as
increases primarily related to the acquisition of Bayer's 50% interest in
Erdoelchemie, the Solvay transaction and the Burmah Castrol chemicals businesses
previously held for sale, were partly offset by downstream rationalization and a
further decrease in former ARCO employees.
96
SHARE OWNERSHIP
Directors
As at March 26, 2002 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:
The Lord Browne of Madingley.. 1,675,684
Dr J G S Buchanan............. 891,391
R F Chase..................... 983,949
W D Ford...................... 503,826
Dr B E Grote.................. 700,845
R L Olver..................... 737,378
J H Bryan..................... 98,760
E B Davis, Jr................. 62,695
Dr D S Julius................. 2,000
C F Knight.................... 30,247
F A Maljers................... 33,492
Dr W E Massey................. 47,378
H M P Miles................... 9,445
Sir Robin Nicholson........... 3,643
Sir Ian Prosser............... 2,826
P D Sutherland................ 7,079
M H Wilson.................... 43,200
Sir Robert Wilson............. 5,478
As at March 26, 2002, 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:
The Lord Browne of Madingley.. 3,032,365
Dr J G S Buchanan............. 333,086
R F Chase..................... 400,774
W D Ford...................... 4,553,580
Dr B E Grote.................. 728,154(a)
R L Olver..................... 706,645
----------
(a) In addition to the above, Dr Grote holds 191,600 Stock Appreciation Rights
(equivalent to 1,149,600 BP ordinary shares)
Additional details regarding the options granted, including exercise price
and expiry dates, are found in this item under the heading 'Compensation --
Share Option Element and Other Option Schemes'.
Employee Share Schemes
BP offers most of its employees the opportunity to acquire a shareholding
in the company through savings-related and matching share plan arrangements.
Such arrangements are now in place in over 60 countries. BP also uses long-term
performance plans (see Item 18 -- Financial Statements -- Note 34) and the
granting of share options as elements of remuneration for executive directors
and senior employees.
During 2001 share options were granted to the executive directors under the
EDLTIP and to certain other categories of employees. For these options the
option price was the market price on the grant date. The options granted to
executive directors reflect BP's performance in terms of 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. The options are
exercisable between the third and the tenth anniversary of the date of grant.
Share options were also granted in 2001 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 scheme)
employees save monthly over a three- or five-year period towards the purchase of
shares at a price fixed when the option is granted. The option price is usually
set at a 20% discount to the market price at the time of grant. The option must
be exercised within six months of maturity of the savings contract; otherwise it
lapses. The plan is run in the UK and a small number of other countries.
97
For 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 40 other
countries.
The Company sponsors a number of savings plans covering most US employees.
Under these plans, employees may contribute up to 18% of their salary subject to
certain regulatory limits. Typically the employee receives a dollar-for-dollar
Company matched contribution for the first 7% of eligible pay contributed to
most of these plans on a before-tax or after-tax basis, or a combination of
both. The precise arrangement depends on the individual's employment contract.
Company contributions are initially invested in BP ADS funds, but employees may
transfer those amounts and may invest their own contributions in more than 200
investment options. The Company's contributions to savings plans during the year
were $125 million ($101 million).
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 2001 the ESOP released 11,508,754 shares (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, 2001 the ESOP held 34,005,910
shares (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 $36 million
($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.
At December 31, 2001, all the 8,148,640 ordinary shares issued to the QUEST
had been transferred to employees exercising options under the UK ShareSave
plan.
2001 2000
------- -------
Employee share options granted during the year (options thousands)
Savings related schemes........................................... 7,901 7,930
BP Share Option Plan.............................................. 58,208 50,461
------- -------
66,109 58,391
======= =======
The exercise prices for BP options granted during the year were (pound)
5.11/$7.36 (7,900,810 options) for savings-related and similar schemes and
(pound) 5.72/$8.23 (weighted average price) for 58,207,741 options granted under
the BP Share Option Plan.
Pursuant to the various BP Group share option schemes, the following
options for BP ordinary shares of the Company were outstanding at March 26,
2002:
Expiry Exercise
Options dates of price
outstanding options per share
------------ ------------ ------------
(shares)
454,497,933 2002 to 2012 $3.47 to $9.97
Further details on share options appear in Item 18 -- Financial Statements
-- Note 33.
98
ITEM 7 -- MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
Major Shareholders
At March 26, 2002, the Company has been notified that JPMorgan Chase Bank
(formerly known as Morgan Guaranty Trust Company), as the approved depositary
for BP American Depositary Shares (ADSs), holds interests through its nominee,
Guaranty Nominees Limited, in 6,846,608,538 ordinary shares (30.50% 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 (3.19% of the Company's
ordinary share capital).
Related Party Transactions
The Group had no material transactions with joint ventures and associated
undertakings during the three years ended December 31, 2001. Transactions
between the Group and its significant joint ventures and associated undertakings
are summarised in Item 18 -- Financial Statements -- Note 41.
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, 2001 to March
26, 2002.
ITEM 8 -- FINANCIAL INFORMATION
CONSOLIDATED STATEMENTS AND OTHER FINANCIAL INFORMATION
Financial Statements
See Item 18 -- Financial Statements.
Dividends
Our financial framework, after adopting FRS 19, is to maintain a ratio of
net debt to net debt plus equity, after adjusting equity for the fixed asset
revaluation adjustment and goodwill consequent upon the ARCO and Burmah Castrol
acquisitions, of around 25-35% and a dividend policy which aims to return to
shareholders around 60% of our replacement cost profit before exceptional items
and after adjusting for special items and acquisition amortization, adjusted to
mid-cycle operating conditions. Special items are non-recurring charges and
credits that are not classified as exceptional items under UK GAAP. Acquisition
amortization refers to depreciation relating to the fixed asset revaluation
adjustment and amortization of goodwill consequent upon the ARCO and Burmah
Castrol acquisitions. Mid-cycle operating conditions reflect not only
adjustments to hydrocarbon prices and margins, but also costs and capacity
utilization to levels which we would expect on average over the long term. If
circumstances give us a larger surplus of cash than is required to fund our
capital programme and meet operational needs, the surplus may be used to pay
down debt to a level at the lower end of our gearing range and/or be returned to
shareholders.
Legal Proceedings
Save as disclosed in the following paragraphs, no member of the Group is a
party to, and no property of a member of the Group is subject to, any pending
legal proceedings which are significant to the Group.
Approximately 200 lawsuits were filed in State and Federal Courts in Alaska
seeking compensatory and punitive damages arising out of the Exxon Valdez oil
spill in Prince William Sound in March 1989. Most of those suits named Exxon
(now ExxonMobil), Alyeska Pipeline Service Company (Alyeska), which operates the
oil terminal at Valdez, and the other oil companies which own Alyeska. Alyeska
initially responded to the spill until the response was taken over by Exxon. BP
owns a 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 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.
99
Since 1987, 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 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.
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.
The Group is subject to numerous and local environment 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 of 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 our accounts in accordance with the Group's accounting policies. See Item 18
-- Financial Statements -- Note 27. 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.
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.
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 BP's ordinary shares may also take place
between an investor and a market-maker, via a member firm, outside the
electronic order book.
In the United States and Canada the Company's securities are traded in the
form of American Depositary Shares (ADSs), for which Morgan Guaranty Trust
Company of New York is the depositary (the Depositary) and transfer agent. The
Depositary's address is 60 Wall Street, New York, NY 10260, USA. Each ADS
represents six BP ordinary shares. ADSs are listed on the New York Stock
Exchange, and are also traded on the Chicago, Pacific and Toronto Stock
Exchanges. ADSs are evidenced by American Depositary Receipts, or ADRs, which
may be issued in either certificated or book entry form.
100
The following table sets forth for the periods indicated the highest and
lowest middle market quotations for the BP ordinary shares of The British
Petroleum Company p.l.c. for 1997 and 1998, and of BP p.l.c. for 1999, 2000 and
2001. 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,
1997...................................... 478.25 331.75 46.50 32.44
1998...................................... 484.25 368.50 48.66 36.50
1999...................................... 643.50 411.00 62.63 40.19
2000...................................... 671.00 444.50 60.63 43.13
2001...................................... 647.00 491.50 55.20 42.20
Year ended December 31,
2000: First quarter....................... 622.50 444.50 60.63 43.13
Second quarter...................... 649.00 506.00 59.31 46.98
Third quarter....................... 671.00 564.50 58.38 50.50
Fourth quarter...................... 646.50 517.50 57.31 45.13
2001: First quarter....................... 609.00 526.50 53.50 46.12
Second quarter...................... 647.00 562.00 55.20 47.50
Third quarter....................... 610.50 504.00 53.05 43.01
Fourth quarter...................... 594.50 491.50 51.95 42.20
2002: First quarter (through March 26).... 617.00 589.50 52.90 49.36
Month of
September 2001............................ 591.50 504.00 51.41 43.01
October 2001.............................. 594.50 528.50 51.95 46.45
November 2001............................. 566.00 491.50 49.65 42.20
December 2001............................. 537.00 504.00 47.07 43.40
January 2002.............................. 550.00 511.00 46.80 43.75
February 2002............................. 592.00 538.00 50.51 45.58
March 2002 (through March 26)............. 617.00 589.50 52.90 49.36
----------
(a) An ADS is equivalent to six BP ordinary shares.
Market prices for the BP ordinary shares on the LSE and in after-hours
trading off the LSE, in each case while the New York Stock Exchange is open, and
the market prices for ADSs on the New York Stock Exchange and other North
American stock exchanges, are closely related due to arbitrage among the various
markets, although differences may exist from time to time due to various factors
including UK stamp duty reserve tax. Trading in ADSs began on the LSE on August
3, 1987.
On March 26, 2002, 1,141,101,423 ADSs (equivalent to 6,846,608,538 BP
ordinary shares or some 30.5% of the total) were outstanding and were held by
approximately 181,000 ADR holders. Of these, about 179,000 had registered
addresses in the USA at that date.
On March 26, 2002 there were approximately 357,000 holders of record of BP
ordinary shares. Of these holders, around 1,400 had registered addresses in the
United States and held a total of some 4,354,000 BP ordinary shares. In
addition, certain accounts of record with registered addresses other than in the
United States hold BP ordinary shares, in whole or in part, beneficially for
United States persons.
101
ITEM 10 -- ADDITIONAL INFORMATION
MEMORANDUM AND ARTICLES OF ASSOCIATION
The following summarizes certain provisions of BP's memorandum and articles
of association and applicable English law. This summary is qualified in its
entirety by reference to the UK Companies Act and BP's memorandum and articles
of association. Information on where investors can obtain copies of the
memorandum and articles of association is described under the heading 'Documents
on Display' under this Item.
Objects and Purposes
BP is incorporated under the name BP p.l.c. and is registered in England
and Wales with registered number 102498. Clause 4 of BP's memorandum of
association provides that its objects include the acquisition of petroleum
bearing lands; the carrying on of refining and dealing businesses in the
petroleum, manufacturing, metallurgical or chemicals businesses; the purchase
and operation of ships and all other vehicles and other conveyances; and the
carrying on of any other businesses calculated to benefit BP. The memorandum
grants BP a range of corporate capabilities to effect these objects.
Directors
The business and affairs of BP shall be managed by the directors.
The articles of association place a general prohibition on a director
voting in respect of any contract or arrangement in which he has a material
interest other than by virtue of his interest in shares in the Company. However,
in the absence of some other material interest not indicated below, a director
is entitled to vote and to be counted in a quorum for the purpose of any vote
relating to a resolution concerning the following matters:
-- The giving of security or indemnity with respect to any money lent or
obligation taken by the director at the request or benefit of the
Company;
-- Any proposal in which he is interested concerning the underwriting of
Company securities or debentures;
-- Any proposal concerning any other company in which he is interested,
directly or indirectly (whether as an officer or shareholder or
otherwise) provided that he and persons connected with him are not the
holder or holders of one percent or more of the voting interest in the
shares of such company;
-- Proposals concerning the modification of certain retirement benefits
schemes under which he may benefit and which has been approved by
either the UK Board of Inland Revenue or by the shareholders; and
-- Any proposal concerning the purchase or maintenance of any insurance
policy under which he may benefit.
The UK Companies Act requires a director of a company who is in any way
interested in a contract or proposed contract with the company to declare the
nature of his interest at a meeting of the directors of the company. The
directors may exercise all the powers of the company to borrow money, except
that the amount remaining undischarged of all moneys borrowed by the company
shall not, without approval of the shareholders, exceed the amount paid up on
the share capital plus the aggregate of the amount of the capital and revenue
reserves of the company. Variation of the borrowing power of the board may only
be effected by amending the articles of association.
Remuneration of non-executive directors shall be determined in the
aggregate by resolution of the shareholders. Remuneration of executive directors
is determined by the Remuneration Committee. This committee is made up of
non-executive directors only. Any director attaining the age of 70 shall retire
at the next annual general meeting. There is no requirement of share ownership
for a director's qualification.
Dividend Rights; Other Rights to Share in Company Profits; Capital Calls
If recommended by the directors of BP, BP shareholders may, by resolution,
declare dividends but no such dividend may be declared in excess of the amount
recommended by the directors. The directors may also pay interim dividends
without obtaining shareholder approval. No dividend may be paid other than out
of profits available for distribution, as determined under UK GAAP and the UK
Companies Act. Dividends on BP ordinary shares are payable only after payment of
dividends on BP preference shares. Any dividend unclaimed after a period of
twelve years from the date of declaration of such dividend shall be forfeited
and reverts to BP.
102
Apart from shareholders' rights to share in BP's profits by dividend (if
any is declared), the articles of association provide that the directors may set
aside:
-- a special reserve fund out of the balance of profits each year to make
up any deficit of cumulative dividend on the BP preference shares; and
-- a general reserve out of the balance of profits each year, which shall
be applicable for any purpose to which the profits of the Company may
properly be applied. This may include capitalization of such sum,
pursuant to an ordinary shareholders' resolution, and distribution to
shareholders as if it were distributed by way of a dividend on the
ordinary shares or in paying up in full unissued ordinary shares for
allotment and distribution as bonus shares.
Any such sums so deposited may be distributed in accordance with the manner
of distribution of dividends as described above.
Holders of shares are not subject to calls on capital by the Company,
provided that the amounts required to be paid on issue have been paid off. All
shares are fully paid.
Voting Rights
The articles of association of BP provide that voting on resolutions at a
shareholders' meeting will be decided on a poll other than resolutions of a
procedural nature, which may be decided on a show of hands. If voting is on a
poll, every shareholder who is present in person or by proxy has one vote for
every ordinary share held and two votes for every (pound)5 in nominal amount of
BP preference shares held. If voting is on a show of hands, each shareholder who
is present at the meeting in person or whose duly appointed proxy is present in
person will have one vote, regardless of the number of shares held, unless a
poll is requested. Shareholders do not have cumulative voting rights.
Holders of record of ordinary shares may appoint a proxy, including a
beneficial owner of those shares, to attend, speak and vote on their behalf at
any shareholders' meeting.
Record holders of BP ADSs also are entitled to attend, speak and vote at
any shareholders' meeting of BP by the appointment by the approved depositary,
JP Morgan Chase Bank (formerly known as Morgan Guaranty Trust Company), of them
as proxies in respect of the ordinary shares represented by their ADSs. Each
such proxy may also appoint a proxy. Alternatively, holders of ADSs are entitled
to vote by supplying their voting instructions to the depositary, who will vote
the ordinary shares represented by their ADSs in accordance with their
instructions.
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 BP 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 resolution, by
determination of the directors), and may issue shares which are to or may be
redeemed.
103
Variation of Rights
The rights attached to any class of shares may be varied with the consent
in writing of holders of 75% of the shares of that class or upon the adoption of
an extraordinary resolution passed at a separate meeting of the holders of the
shares of that class. At every such separate meeting, all of the provisions of
the articles of association relating to proceedings at a general meeting apply,
except that the quorum with respect to meeting to change the rights attached to
the preference shares is 10% or more of the shares of that class, and the quorum
to change the rights attached to the ordinary shares is one third or more of the
shares of that class.
Shareholders' Meetings and Notices
Shareholders must provide BP with 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.
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.
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.
MATERIAL CONTRACTS
The following contract (not being contracts entered into in the ordinary
course of business) has been entered into by members of the Group since
January 1, 1999 that is material:
A merger agreement under Delaware law dated March 31, 1999 and amended as
of July 12, 1999 and again as of March 27, 2000 pursuant to which Prairie
Holdings (a wholly-owned subsidiary of BP) was to be merged with and into
ARCO and ARCO was to become a wholly-owned subsidiary of BP. Under the
terms of the merger, each ARCO shareholder was entitled to receive 9.84 BP
ordinary shares (in the form of BP ADSs) for each ARCO share. The merger
agreement contained certain customary representations and warranties by
ARCO and BP with respect to themselves and their respective subsidiaries,
regarding, among other things, due organization, good standing and
qualification, capital structure, corporate authority and compliance with
corporate governance documents, government filings, reports and financial
statements, litigation and liabilities, absence of certain changes,
employee benefits, environmental matters and tax matters. The merger was
declared effective on April 18, 2000, at which time 3,186,006,476 BP
ordinary shares were issued as consideration in the merger.
EXCHANGE CONTROLS AND OTHER LIMITATIONS AFFECTING SECURITY HOLDERS
There are currently no UK foreign exchange controls or restrictions on
remittances of dividends on the BP ordinary shares or on the conduct of the
Company's operations.
There are no limitations, either under the laws of the UK or under the
articles of association of BP p.l.c., restricting the right of non-resident or
foreign owners to hold or vote BP ordinary or preference shares in the Company.
104
TAXATION
The following summary of the principal UK and certain US tax consequences
of ownership of ADSs or BP ordinary shares is based in part on representations
of Morgan Guaranty Trust Company of New York as Depositary for the ADRs
evidencing the ADSs and assumes that each obligation in the deposit agreement
among the Company, the Depositary and the holders from time to time of ADRs and
any related agreement will be performed in accordance with its terms.
Beneficial owners of ADSs who are resident in the USA are treated as the
owners of the underlying BP ordinary shares for the purposes of the income tax
convention between the USA and the UK (the Convention) and for the purposes of
the US Internal Revenue Code of 1986, as amended (the Code). Unless otherwise
stated, references to 'shareholders' or 'shareholder' below are to persons who
are the beneficial owners of the underlying BP ordinary shares. It should be
noted that a new income tax convention between the USA and the UK was signed on
July 24, 2001 and is awaiting ratification by both countries.
For purposes of this discussion, a US Holder is a beneficial owner of the
Company's shares who for the purposes of the Convention is not a US corporation
owning directly or indirectly 10% or more of the Company's voting stock, and who
is a resident of the USA and is not a resident of the UK.
Certain UK and US tax consequences of owning ADSs
The tax credit for an individual shareholder resident in the UK is reduced
to 1/9 of the amount of the net dividend (or 10% of the net dividend plus the
tax credit). This tax credit continues to be available to set against the
individual's tax liability on the dividend, but is no longer refundable to the
individual.
For purposes of this section, with respect to any dividend paid by the
Company, Refund means an amount equal to the tax credit available to individual
shareholders resident in the UK in respect of such dividend, less a withholding
tax equal to 15% (limited to the amount of the tax credit) of the aggregate of
such tax credit and such dividend.
A US holder, as defined above, that is eligible for the benefits under the
convention (an eligible US Holder) is entitled, in principle, to receive the
Refund. However, no actual refund is available to eligible US Holders under the
convention since the amount of witholding tax (at 15%) exceeds the 10% tax
credit available to individual shareholders resident in the UK. Thus, for
example, a dividend of $8.00, will result in a net receipt after UK tax but
before US tax of $8.00 that is the withholding tax does not reduce the dividend
below the net dividend of $8.00.
Dividends (including amounts in respect of the tax credit and any amounts
withheld) must be included in gross income by a shareholder subject to US
taxation and will generally be treated as foreign source 'passive income' or, in
the case of certain US Holders, 'financial services income' for foreign tax
credit limitations purposes. Such dividends will generally not be eligible for
the dividends received deduction allowed to US corporations. The IRS has
recently confirmed, that, in the case of Eligible US Holders, subject to certain
limitations, the UK withholding tax as determined by the Convention (that is an
amount equal to 1/9 of the cash dividend) will be treated as a foreign income
tax that is eligible for credit against the US Holders' federal income tax. To
qualify for such credit, Eligible US Holders must make an election on Form 8833
(a Treaty-Based Return Position Disclosure, under Section 6114 or 7701(b)),
which must be filed with their tax return, in addition to any other filings that
may be required. At the end of the calendar year during which the dividends are
paid, US Holders will receive a Form 1099 confirming the amount of dividends
received.
Share Dividend Choice for BP ADR Holders
ADR holders electing to receive ADSs instead of a cash dividend (see Item 3
-- Key Information -- Dividends) will not be entitled to any Refund from the UK
Inland Revenue, nor will the 15% withholding tax apply, with respect to such
dividends.
For US tax purposes the receipt of additional ADSs will be treated as a
dividend distribution. An ADR holder who is subject to US taxation will
generally be treated as having received gross income equal to the fair market
value of the ADSs (or fraction thereof) on the date of the share distribution in
London (with no reduction for the stamp duty reserve tax referred to below). The
US resident ADR holder will receive a tax basis in the ADSs equal to such fair
market value. Corporations will not be entitled to a dividends received
deduction on receipt of a share dividend.
105
UK Taxation of Capital Gains
A US Holder will be liable to UK tax on capital gains realized on the sale
or other disposition of BP ordinary shares only if the US Holder is resident
(or, in the case of an individual, ordinarily resident) for UK tax purposes in
the UK or if he carries on a trade, profession or vocation in the UK through a
permanent establishment and the BP ordinary shares are (i) used for the purposes
of the trade, profession or vocation, or (ii) used, held or acquired for the
purposes of the permanent establishment.
The liability to UK capital gains tax for a US Holder of ADRs is the same
as that for a US Holder of BP ordinary shares, except that a US Holder of ADRs
who is resident but not domiciled in the UK will not be taxed on gains realized
on the sale or other disposition of ADSs if the proceeds are not remitted to the
UK.
UK Inheritance Tax
UK capital transfer tax was restructured and renamed 'inheritance tax' in
1986. The US-UK double taxation convention relating to estate and gift taxes
(the Estate Tax Convention) applies to inheritance tax. ADRs held by an
individual who is domiciled for the purposes of the Estate Tax Convention in the
USA and is not for the purposes of the Estate Tax Convention a national of the
UK will not be subject to inheritance tax on death or on transfer during the
individual's lifetime unless, among other things, the ADSs are part of the
business property of a permanent establishment situated in the UK or pertain to
a fixed base situated in the UK used for the performance of independent personal
services. In the exceptional case where ADSs are subject both to inheritance tax
and to US Federal gift or estate tax, the Estate Tax Convention generally
provides for tax paid in the UK to be credited against tax payable in the USA or
for tax paid in the USA to be credited against tax payable in the UK based on
priority rules set forth in the Estate Tax Convention.
UK Stamp Duty and Stamp Duty Reserve Tax
The statements below relate to what is understood to be the current
practice of the UK Inland Revenue under existing law.
Provided that the instrument of transfer is not executed in the UK and
remains at all times outside the UK, and the transfer does not relate to any
matter or thing done or to be done in the UK, no UK stamp duty is payable on the
acquisition or transfer of ADSs. Neither will an agreement to transfer ADSs in
the form of ADRs give rise to a liability to stamp duty reserve tax.
Purchases of BP ordinary shares, as opposed to ADSs, through the CREST
system of paperless share transfers will be subject to stamp duty reserve tax at
a rate of 0.5%. The charge will arise as soon as there is an agreement for the
transfer of the shares (or, in the case of a conditional agreement, when the
condition is fulfilled). The stamp duty reserve tax will apply to agreements to
transfer BP ordinary shares even if the agreement is made outside the UK between
two non-residents. Purchases of BP ordinary shares outside the CREST system are
subject either to stamp duty at a rate of 50 pence per (pound) 100 (or part), or
stamp duty reserve tax at 0.5%. Stamp duty and stamp duty reserve tax are
generally the liability of the purchaser. A subsequent transfer of BP ordinary
shares to the Depositary's nominee will give rise to further stamp duty at the
rate of (pound) 1.50 per (pound) 100 (or part) or stamp duty reserve tax at the
rate of 1.5% of the value of the BP ordinary shares at the time of the transfer.
A transfer of the underlying BP ordinary shares to an ADR holder upon
cancellation of the ADSs without transfer of beneficial ownership will give rise
to UK stamp duty at the rate of (pound) 5 per transfer.
An ADR holder electing to receive ADSs instead of a cash dividend will be
responsible for the stamp duty reserve tax due on issue of shares to the
Depositary's nominee and calculated at the rate of 1.5% on the issue price of
the shares. Current UK Inland Revenue practice is to calculate the issue price
by reference to the total cash receipt (i.e. cash dividend plus the Refund if
any) to which a US Holder would have been entitled had the election to receive
ADSs instead of a cash dividend not been made. ADR holders electing to receive
ADSs instead of the cash dividend authorize the Depositary to sell sufficient
shares to cover this liability.
DOCUMENTS ON DISPLAY
It is possible to read and copy documents referred to in this annual report
on Form 20-F that have been filed with the SEC at the SEC's public reference
room located at 450 Fifth Street, NW, Washington, DC 20549 and at the SEC's
other public reference rooms in New York City and Chicago. Please call the SEC
at 1-800-SEC-0330 for further information on the public reference rooms and
their copy charges. The SEC filings are also available to the public from
commercial document retrieval services and, for most recent BP periodic filings
only, at the Internet world wide web site maintained by the SEC at www.sec.gov.
106
ITEM 11 -- QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
BP is exposed to a number of different market risks arising from the
Group's normal business activities. Market risk is the possibility that changes
in currency exchange rates, interest rates or oil and natural gas prices will
adversely affect the value of the Group's financial assets, liabilities or
expected future cash flows. The Group has developed policies aimed at managing
the volatility inherent in certain of these natural business exposures and in
accordance with these policies the Group enters into various transactions using
derivative financial and commodity instruments (derivatives). Derivatives are
contracts whose value is derived from one or more underlying financial
instruments, indices or prices which are defined in the contract. We also trade
derivatives in conjunction with these risk management activities.
In market risk management and 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 financial instrument and derivative activity, whether for risk
management or trading, is carried out by specialist teams which have the
appropriate skills, experience and supervision. These teams are subject to close
financial and management control, meeting generally accepted industry practice
and reflecting the principles of the Group of Thirty Global Derivatives Study
recommendations. 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. As part of its approach to ensuring that
control over trading is maintained to a high and consistent standard, the
Group's business units dealing in the oil, natural gas and financial markets
were brought together within a single integrated supply and trading organization
during 2001.
Further information about BP's use of derivatives, their characteristics,
and the accounting treatment thereof is given in Item 18 -- Note 1 and Note 28.
The Group's accounting policies under UK GAAP do not satisfy the criteria
for hedge accounting under Statement of Financial Accounting Standards No. 133
'Accounting for Derivative Instruments and Hedging Activities'. The Group does
not intend to modify its practice under UK GAAP. See Item 18 -- Financial
Statements -- Note 43 for further information.
Risk Management
Foreign Currency Exchange Rate Risk
Fluctuations in exchange rates can have significant effects on 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.
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, that part of the quarterly dividend which is paid in sterling,
the sterling cash flow requirements for UK Corporation Tax, and the capital
expenditure and operational requirements of Exploration and Production, mainly
in the UK. In addition, most of the Group's borrowings are in US dollars, are
hedged with respect to the US dollar, or are swapped into US dollars. At
December 31, 2001, the total of foreign currency borrowings not swapped into US
dollars amounted to $449 million. The principal elements of this are $133
million of borrowings in sterling, $85 million in Malaysian ringgit, $77 million
in Trinidad and Tobago dollars and $70 million in South African rand.
107
The following table provides information about the Group's foreign currency
derivative financial instruments. These include foreign currency forward
exchange agreements (forwards) that are sensitive to changes in the sterling/US
dollar, euro/US dollar and Norwegian krone/US dollar exchange rates. Where
foreign currency denominated borrowings are swapped into US dollars using
forwards or currency interest rate swaps such that currency risk is completely
eliminated, neither the borrowing nor the derivative are included in the table.
The table presents the notional amounts and weighted average contractual
exchange rates by contractual maturity dates and exclude forwards that have
offsetting positions. Only significant forward positions are included in the
tables. The notional amounts of forwards are translated into US dollars at the
exchange rate included in the contract at inception. The majority of the
sterling contracts consist of forwards relating to sterling-based capital leases
which effectively convert the lease obligation from sterling into US dollars.
The remaining contracts relate to sterling requirements for UK tax payments and
UK dividend payments and net operational expenditures. The euro forward
contracts relate mainly to payments for capital expenditure. The Norwegian krone
forward contracts relate to the Group's Norwegian tax payments over the next
year. The fair value represents an estimate of the gain or loss which would be
realized if the contracts were settled at the balance sheet date.
The fair values for the foreign exchange contracts in the table below are
based on market prices of comparable instruments (forwards). These derivative
contracts constitute a hedge; any change in the fair value or expected cash
flows is offset by an opposite change in the market value or expected cash flows
of the asset, liability or transaction being hedged.
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
Fair value
asset/
2001 2002 2003 2004 Total (liability)
------ ------ ------ ------ ------ ------------
($ million)
At December 31, 2000
Forwards
Receive sterling/pay US dollars
Contract amount..................... 3,299 -- -- -- 3,299 (30)
Weighted average contractual
exchange rate..................... 1.52
Receive euro/pay US dollars
Contract amount..................... 663 45 23 13 744 (16)
Weighted average contractual
exchange rate..................... 1.01
Receive Norwegian krone/pay US dollars
Contract amount..................... 199 -- -- -- 199 6
Weighted average contractual
exchange rate (a)................. 9.19
---------------
(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.
108
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 2001, the proportion of floating
rate debt was in the range of 32-43% of total net debt outstanding.
The following table shows, by major currency, the Group's borrowings at
December 31, 2001 and 2000 and the weighted average interest rates achieved at
those dates through a combination of borrowings and other interest rate
sensitive instruments entered into to manage interest rate exposure.
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, 2001
US dollar..................... 7 8 11,485 2 7,842 19,327
Sterling...................... -- -- -- 4 133 133
Other currencies.............. 10 29 122 6 194 316
-------- -------- --------
11,607 8,169 19,776
======== ======== ========
At December 31, 2000
US dollar..................... 7 9 10,199 6 8,326 18,525
Sterling...................... -- -- -- 6 449 449
Other currencies.............. 8 30 45 10 247 292
-------- -------- --------
10,244 9,022 19,266
======== ======== ========
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, 2001. 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, 2002, the Group's 2002 earnings before taxes would
decrease by approximately $100 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, 2001 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.
109
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 organization uses the
full range of conventional oil price-related financial and commodity derivatives
available in the oil markets.
The derivative instruments used for hedging purposes do not expose the
Group to market risk because the change in their market value is offset by an
equal and opposite change in the market value of the asset, liability or
transaction being hedged. The values at risk in respect of derivatives held for
oil price risk management purposes are shown in isolation in the table below.
The items being hedged are not included in the values at risk.
The value at risk model used is that discussed under Trading below, except
that value at risk in respect of oil price risk management does not take into
account physical crude oil or refined product positions held by the Group. Thus
the value at risk calculation for oil price exposure includes derivative
financial instruments such as exchange-traded futures and options, swap
agreements and over-the-counter options and derivative commodity instruments
(commodity contracts that permit settlement either by delivery of the underlying
commodity or in cash) such as forward contracts. The values at risk represent
the potential gain or loss in fair values over a 24-hour period with a 99.7%
confidence level.
The following table shows values at risk for oil price risk management
activities.
High Low Average December 31
------ ------ ------- ------------
($ million)
2001
Oil price contracts............................. 11 4 7 7
2000
Oil price contracts............................. 18 11 15 11
1999
Oil price contracts............................. 5 3 3 5
Natural Gas Price Risk
BP's general policy with respect to natural gas price risk is to manage
only a portion of its exposure to price fluctuations. Natural gas swaps, options
and futures are used to convert specific sales and purchases contracts from
fixed prices to market prices. Swaps are also used to hedge exposure to price
differentials between locations. We also use derivatives to fix prices which are
favorable with respect to our forecasts of future prices.
The table below provides information about the Group's material swaps
contracts that are sensitive to changes in natural gas prices. Contract amount
represents the notional amount of the contract. Fair value represents an
estimate of the gain or loss which would be realized if the contracts were
settled at the balance sheet date. Weighted average price represents the
year-end forward price for futures, the fixed price and the year-end forward
price related to the settlement month for swaps; and the weighted average strike
price for options.
At December 31, 2001, in addition to the swaps contracts shown in the table
there were options contracts with aggregate notional amounts of $1,090 million
($7 million at December 31, 2000) and terms of up to one year and futures
contracts with aggregate gross contract amounts of $35 million ($96 million at
December 31, 2000).
110
Weighted
Gross Fair value average price
Contract ---------------------- -----------------
Quantity amount Asset Liability Receive Pay
-------- ------ ----- --------- ------- ----
(Btu trillion)(a) ($ million) ($ million) ($ per mmBtu)(b)
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
At December 31, 2000
Maturing in 2001
Swaps
Receive variable/pay fixed..... 30 129 72 (1) 4.30 6.80
Receive fixed/pay variable..... 12 67 1 (28) 8.18 5.80
Receive and pay variable....... 265 1,932 46 (72) 7.28 7.18
Maturing in 2002
Swaps
Receive variable/pay fixed..... 13 54 12 (1) 3.90 4.30
Receive fixed/pay variable..... 1 2 -- (1) 3.47 3.20
Receive and pay variable....... 40 198 2 (11) 4.87 4.64
Maturing in 2003
Swaps
Receive variable/pay fixed..... 2 7 -- -- 4.00 3.87
Receive and pay variable....... 15 56 -- -- 3.86 3.87
Maturing in 2004
Swaps
Receive variable/pay fixed..... 2 7 -- -- 3.91 4.01
Receive and pay variable....... 2 7 -- -- 3.84 3.83
Maturing in 2005
Swaps
Receive variable/pay fixed..... 2 7 -- -- 3.91 4.01
Receive and pay variable....... 2 7 -- -- 3.86 3.83
Maturing beyond 2005
Swaps
Receive variable/pay fixed..... 5 19 -- -- 3.99 4.01
Receive and pay variable....... 5 19 -- -- 3.87 3.83
---------------
(a) British thermal units (Btu)
(b) Million British thermal units (mmBtu)
111
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 organization
undertakes trading in the full range of conventional derivative financial and
commodity instruments and physical cargoes available in the oil markets. The
Group also uses financial and commodity derivatives to manage certain of its
exposures to price fluctuations on natural gas transactions. These activities
are monitored and measured separately from the risk management activity and are
subject to maximum value at risk limits authorized by the board. The Group
increased the volume of its natural gas trading activity in 2001.
The Group measures its market risk exposure, that is 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 model takes account of derivative financial instruments such as
interest rate forward and futures contracts, swap agreements, options and
swaptions; foreign exchange forward and futures contracts, swap agreements and
options; and oil and natural gas price futures, swap agreements and options.
Financial assets and liabilities and physical crude oil and refined products
that are treated as trading positions are also included in these calculations.
The value-at-risk calculation for oil 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)
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
1999
Interest rate trading.......................... 1 -- 1 --
Foreign exchange trading....................... 13 -- 3 1
Oil price trading.............................. 15 5 9 10
112
The following table shows the changes during the year in the net fair value
of non-exchange-traded 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, 2001...... -- -- 36 24
Contracts realized or settled in the year....... -- -- (37) (36)
Fair value of new contracts when entered into
during the year............................... -- -- -- --
Changes in fair values attributable to changes
in valuation techniques and assumptions....... -- -- -- --
Other changes in fair values.................... -- (3) 27 24
--------- --------- --------- ----------
Fair value of contracts at December 31, 2001 -- (3) 26 12
========= ========= ========= ==========
The following table shows the net fair value of non-exchange-traded
contracts held for trading purposes at December 31, 2001 analyzed by maturity
period and by methodology of fair value estimation.
Fair value of contracts at December 31, 2001
----------------------------------------------------------------
Maturity Maturity Total
less than Maturity Maturity over fair
1 year 1-3 years 4-5 years 5 years value
------- --------- --------- -------- -------
($ million)
Prices actively quoted........................... 9 1 -- (2) 8
Prices provided by other external sources........ 3 3 -- -- 6
Prices based on models and other
valuation methods.............................. 17 4 -- -- 21
------ ------ ------ ------ ------
29 8 -- (2) 35
====== ====== ====== ====== ======
ITEM 12 -- DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
Not applicable
113
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.
114
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, 2001, 2000, and 1999 F-2
Consolidated Balance Sheet at December 31, 2001 and 2000...................... F-3
Consolidated Statement of Cash Flows for the Years
Ended December 31, 2001, 2000 and 1999...................................... F-4
Statement of Total Recognized Gains and Losses for the Years
Ended December 31, 2001, 2000 and 1999...................................... F-4
Statement of Changes in BP Shareholders' Interest for
the Years Ended December 31, 2001, 2000 and 1999............................ F-5
Notes to Financial Statements................................................. F-7
Supplementary Oil and Gas Information (Unaudited)............................. F-109
Schedule for the Years Ended December 31, 2001, 2000 and 1999
Schedule II Valuation and Qualifying Accounts............................... S-1
ITEM 19 -- EXHIBITS
The following documents are filed as part of this annual report:
Exhibit 1 Memorandum and Articles of Association of BP 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
* Incorporated by reference to the Company's annual report on Form 20-F for
the year ended December 31, 2000.
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.
115
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)
Dated: March 28, 2002 /S/ D. J. PEARL
............................
D. J. PEARL
Deputy Company Secretary
116
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, 2001 and 2000, 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,
2001. 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, 2001 and 2000, and the consolidated results of its
operations and its consolidated cash flows for each of the three years in the
period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United Kingdom which differ in certain respects from
those followed in the United States (see Note 43 of Notes to Financial
Statements). Also, in our opinion, the related financial statement schedule,
when considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
/S/ ERNST & YOUNG LLP
--------------------
London, England Ernst & Young LLP
February 12, 2002
--------------------------------------------------------------------------------
CONSENT OF INDEPENDENT AUDITORS
We consent to the incorporation by reference of our report dated February
12, 2002, 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, 2001
in the following Registration Statements:
Registration Statements on Form F-3 (File Nos. 333-9790 and 333-65996) of
BP p.l.c.;
Registration Statements on Form F-3 (File Nos. 33-39075 and 33-20338) of BP
America Inc. and BP p.l.c.;
Registration Statement on Form F-3 (File No. 33-29102) of The Standard Oil
Company and 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 and 333-74414) of BP p.l.c.
/S/ ERNST & YOUNG LLP
--------------------
London, England Ernst & Young LLP
March 28, 2002
F - 1
CONSOLIDATED STATEMENT OF INCOME
Years ended December 31,
--------------------------
Note 2001 2000 1999
---- ----- ----- -----
($ million, except per share amounts)
Turnover............................................ 175,389 161,826 101,180
Less: Joint ventures................................ 1,171 13,764 17,614
------ ------ ------
Group turnover...................................... 2 174,218 148,062 83,566
Replacement cost of sales........................... 146,893 120,720 68,615
Production taxes.................................... 3 1,689 2,061 1,017
------ ------ ------
Gross profit........................................ 25,636 25,281 13,934
Distribution and administration expenses............ 4 10,918 9,331 6,064
Exploration expense................................. 480 599 548
------ ------ ------
14,238 15,351 7,322
Other income........................................ 5 694 805 414
------ ------ ------
Group replacement cost operating profit............. 14,932 16,156 7,736
Share of profits of joint ventures.................. 443 808 555
Share of profits of associated undertakings......... 760 792 603
------ ------ ------
Total replacement cost operating profit............. 16,135 17,756 8,894
Profit (loss) on sale of businesses
or termination of operations...................... 6 (68) 132 363
Profit (loss) on sale of fixed assets............... 6 603 88 (700)
Restructuring costs................................. 6 -- -- (1,943)
------ ------ ------
Replacement cost profit before interest and tax..... 16,670 17,976 6,614
Inventory holding gains (losses).................... (1,900) 728 1,728
------ ------ ------
Historical cost profit before interest and tax 14,770 18,704 8,342
Interest expense.................................... 7 1,670 1,770 1,316
------ ------ ------
Profit before taxation.............................. 13,100 16,934 7,026
Taxation............................................ 9 5,017 4,972 1,880
------ ------ ------
Profit after taxation............................... 8,083 11,962 5,146
Minority shareholders' interest..................... 73 92 138
------ ------ ------
Profit for the year*................................ 8,010 11,870 5,008
Dividend requirements on preference shares*......... 2 2 2
------ ------ ------
Profit for the year applicable
to ordinary shares* 8,008 11,868 5,006
====== ====== ======
Profit per ordinary share - cents
Basic .............................................. 11 35.70 54.85 25.82
Diluted............................................. 11 35.48 54.48 25.68
====== ====== ======
Dividends per ordinary share - cents................ 10 22.0 20.5 20.0
====== ====== ======
Average number outstanding of 25 cents
ordinary shares (in millions)..................... 22,436 21,638 19,386
====== ====== ======
----------
* A summary of the adjustments to profit for the year of the Group which would
be required if generally accepted accounting principles in the United States
had been applied instead of those generally accepted in the United Kingdom is
given in Note 43.
The Notes to Financial Statements are an integral part of this Statement.
F-2
CONSOLIDATED BALANCE SHEET
December 31,
---------------------------------
Note 2001 2000
------ --------------- ----------------
($ million)
Fixed assets
Intangible assets........................ 19 15,593 16,893
Tangible assets.......................... 20 77,410 75,173
Investments
Joint ventures
Gross assets.......................... 4,661 3,641
Gross liabilities..................... 800 757
------ ------
Net investment........................ 21 3,861 2,884
Associated undertakings................. 21 5,567 5,455
Other................................... 21 2,619 3,414
------ ------
12,047 11,753
------ ------
Total fixed assets......................... 105,050 103,819
Current assets
Business held for resale................. -- 636
Inventories.............................. 22 7,631 9,234
Trade receivables........................ 23 15,436 17,813
Other receivables falling due
Within one year......................... 23 6,552 5,995
After more than one year................ 23 4,681 4,610
Investments.............................. 24 450 661
Cash at bank and in hand................. 1,358 1,170
------ ------
36,108 40,119
------ ------
Current liabilities --
falling due within one year
Finance debt............................. 25 9,090 6,418
Trade payables........................... 26 13,129 14,363
Other accounts payable and
accrued liabilities.................... 26 15,395 17,747
------ ------
37,614 38,528
------ ------
Net current assets ........................ (1,506) 1,591
------ ------
Total assets less current liabilities 103,544 105,410
Noncurrent liabilities
Finance debt............................. 25 12,327 14,772
Accounts payable and accrued liabilities. 3,086 3,842
Provisions for liabilities and charges
Deferred taxation........................ 9 1,655 1,822
Other.................................... 27 11,482 10,973
------ ------
28,550 31,409
------ ------
Net assets................................. 74,994 74,001
Minority shareholders' interest............ 627 585
------ ------
BP shareholders' interest*................. 74,367 73,416
====== ======
Represented by:
Capital shares
Preference............................... 21 21
Ordinary................................. 5,608 5,632
Paid in surplus............................ 29 4,014 3,770
Merger reserve............................. 29 26,983 26,869
Other reserves............................. 29 223 456
Retained earnings.......................... 29/30 37,518 36,668
------ ------
74,367 73,416
====== ======
----------
* A summary of the adjustments to BP shareholders' interest which would be
required if generally accepted accounting principles in the United States
had been applied instead of those generally accepted in the United Kingdom
is given in Note 43.
The Notes to Financial Statements are an integral part of this Balance Sheet.
F - 3
CONSOLIDATED STATEMENT OF CASH FLOWS
Years ended December 31,
--------------------------
Note 2001 2000 1999
---- ----- ----- -----
($ million)
Net cash inflow from operating activities................ 31 22,409 20,416 10,290
------ ------ ------
Dividends from joint ventures............................ 104 645 949
------ ------ ------
Dividends from associated undertakings................... 528 394 219
------ ------ ------
Servicing of finance and returns on investments
Interest received........................................ 256 444 179
Interest paid............................................ (1,282) (1,354) (1,065)
Dividends received....................................... 132 42 34
Dividends paid to minority shareholders.................. (54) (24) (151)
------ ------ ------
Net cash outflow from servicing of finance and
returns on investments................................. (948) (892) (1,003)
------ ------ ------
Taxation
UK corporation tax....................................... (1,058) (869) (559)
Overseas tax............................................. (3,602) (5,329) (701)
------ ------ ------
Tax paid................................................. (4,660) (6,198) (1,260)
------ ------ ------
Capital expenditure and financial investment
Payments for tangible and intangible fixed assets........ (12,142) (8,837) (6,371)
Payments for fixed assets -- investments................. (72) (1,264) (163)
Proceeds from the sale of fixed assets................... 18 2,365 3,029 1,149
------ ------ ------
Net cash outflow for capital expenditure
and financial investment............................... (9,849) (7,072) (5,385)
------ ------ ------
Acquisitions and disposals
Investments in associated undertakings................... (586) (985) (197)
Acquisitions............................................. 17 (1,210) (6,265) (102)
Net investment in joint ventures......................... (497) (218) (750)
Proceeds from the sale of businesses..................... 18 538 8,333 1,292
------ ------ ------
Net cash (outflow) inflow for acquisitions
and disposals.......................................... (1,755) 865 243
------ ------ ------
Equity dividends paid.................................... (4,827) (4,415) (4,135)
------ ------ ------
Net cash inflow (outflow)................................ 1,002 3,743 (82)
====== ====== ======
Financing................................................ 31 972 3,413 (954)
Management of liquid resources........................... 31 (211) 452 (93)
Increase (decrease) in cash.............................. 31 241 (122) 965
------ ------ ------
1,002 3,743 (82)
====== ====== ======
--------------------------------------------------------------------------------
STATEMENT OF TOTAL RECOGNIZED GAINS AND LOSSES
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Profit for the year...................................... 8,010 11,870 5,008
Currency translation differences......................... (908) (2,508) (921)
------ ------ ------
Total recognized gains and losses relating to the year... 7,102 9,362 4,087
Prior year adjustment -- change in accounting policy..... -- -- 715
------ ------ ------
Total recognized gains and losses........................ 7,102 9,362 4,802
====== ====== ======
---------------
For a cash flow statement and a statement of comprehensive income prepared
on the basis of US GAAP see Note 43 -- US generally accepted accounting
principles.
--------------------------------------------------------------------------------
The Notes to Financial Statements are an integral part of these Statements.
F-4
STATEMENT OF CHANGES IN BP SHAREHOLDERS' INTEREST
The Company's authorized ordinary share capital at December 31, 2001 and
2000 was 36 billion shares of 25 cents each, amounting to $9 billion. At
December 31,1999 the authorized ordinary share capital was 24 billion shares of
25 cents each, amounting to $6 billion. In addition the company has authorized
preference share capital of 12,750,000 shares of (pound)1 each ($21 million).
Details of movements in share capital are shown in Note 30.
The allotted, called up and fully paid share capital at December 31, was as
follows:
Shares
---------------------
Authorized Issued Amount
----------- --------- --------
($ million)
Non-equity-- preference shares
8% cumulative first preference
shares of(pound)1 each
at December 31, 2001, 2000 and 1999.......... 7,250,000 7,232,838 12
=========== ========= ========
9% cumulative second preference
shares of(pound)1 each
at December 31, 2001, 2000 and 1999.......... 5,500,000 5,473,414 9
=========== ========= ========
Equity -- ordinary shares of 25 cents each
Authorized
December 31, 2001.............................. 36,000,000,000
==============
Years ended December 31,
----------------------------------------------------------------------------
2001 2000 1999
---------------------- ---------------------- ----------------------
ISSUED Shares of Shares of Shares of
25 cents each Amount 25 cents each Amount 25 cents each Amount
------------- ------ ------------- ------ ------------- ------
(thousands) ($ million) (thousands) ($ million) (thousands) ($ million)
January 1................ 22,528,747 5,632 19,484,024 4,871 19,366,020 4,842
Employee share schemes (a) 33,461 8 38,112 9 66,162 16
Share dividend plan (b).. -- -- -- -- 51,842 13
ARCO (c)................. 23,798 7 -- -- -- --
ARCO acquisition......... -- -- 3,228,274 807 -- --
Share buyback (d)........ (153,929) (39) (221,663) (55) -- --
-------- -------- ---------- ------- ---------- -------
December 31.............. 22,432,077 5,608 22,528,747 5,632 19,484,024 4,871
========== ======== ========== ======= ========== =======
Paid in surplus
January 1................ 3,770 3,684 3,386
Premium on shares issued:
Employee share schemes. 118 250 250
ARCO................... 51 -- --
Share dividend plan ... -- -- (13)
Share buyback............ 39 55 --
Stamp duty reserve tax... -- (295) --
Qualifying Employee Share
Ownership Trust (e).... 36 76 61
-------- -------- --------
December 31.............. 4,014 3,770 3,684
======== ======== ========
The Notes to Financial Statements are an integral part of this Statement.
F-5
STATEMENT OF CHANGES IN BP SHAREHOLDERS' INTEREST (Concluded)
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Merger reserve
January 1.......................................... 26,869 697 697
ARCO (c)........................................... 114 -- --
ARCO acquisition................................... -- 26,172 --
------ ------ ------
December 31........................................ 26,983 26,869 697
====== ====== ======
Other reserves
January 1.......................................... 456 -- --
ARCO(c)............................................ (117) -- --
ARCO acquisition................................... -- 456 --
Redemption of ARCO preference shares (f)........... (116) -- --
------ ------ ------
December 31........................................ 223 456 --
====== ====== ======
Retained earnings
January 1.......................................... 36,668 34,008 33,555
Exchange adjustment................................ (908) (2,508) (921)
Share dividend plan................................ -- -- 311
Share buyback...................................... (1,281) (2,001) --
Qualifying Employee Share Ownership Trust (e)...... (36) (76) (61)
Profit for the year................................ 8,010 11,870 5,008
Dividends (g)
Preference (non-equity)........................... (2) (2) (2)
Ordinary (equity)................................. (4,933) (4,623) (3,882)
------ ------ ------
December 31........................................ 37,518 36,668 34,008
====== ====== ======
----------
(a) Employee share schemes. During the year 33,460,856 ordinary shares were
issued under the BP, Amoco and Burmah Castrol employee share schemes.
(b) During 1999 there were 51,842,146 BP ordinary shares issued under the share
dividend plan at par value, by capitalization of paid in surplus.
(c) ARCO. 10,728,978 ordinary shares were issued in connection with the
conversion of ARCO preference shares and a further 13,069,008 ordinary
shares were issued in respect of ARCO employee share option schemes.
(d) Share buyback. The Company purchased for cancellation 153,928,949 ordinary
shares for a total consideration of $1,281 million.
(e) See Note 33 -- Employee share schemes.
(f) Redemption of ARCO preference shares. A cash tender offer was made in March
2001 for the outstanding ARCO preference shares.
(g) See Note 10 -- Dividends per ordinary share.
(h) See Note 30 -- Retained earnings.
(i) Voting on substantive resolutions tabled at a general meeting is on a poll.
On a poll, shareholders present in person or by proxy have two votes for
every (pound)5 in nominal amount of the first and second preference shares
held and one vote for every ordinary share held. On a show of hands vote on
other resolutions (procedural matters) at a general meeting, shareholders
present in person or by proxy have one vote each.
In the event of the winding up of the Company preference shareholders would
be entitled to a sum equal to the capital paid up on the preference shares
plus an amount in respect of accrued and unpaid dividends and a premium
equal to the higher of (i) 10% of the capital paid up on the preference
shares and (ii) the excess of the average market price of such shares on
the London Stock Exchange during the previous six months over par value.
The Notes to Financial Statements are an integral part of this Statement.
F-6
NOTES TO FINANCIAL STATEMENTS
Note 1 -- Accounting policies
Accounting standards
These accounts are prepared in accordance with applicable UK accounting
standards. Two new Financial Reporting Standards: No.17 'Retirement Benefits'
(FRS 17) and No.18 'Accounting Policies' (FRS 18) are effective for the Group's
2001 year end reporting. The accounts contain the transitional disclosures
required by FRS 17. The adoption of FRS 18 has had no effect on the results for
the year nor required any restatement of prior year comparatives.
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, limited to a maximum period of 20
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-7
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (continued)
Accounting convention
The accounts are prepared under the historical cost convention. Historical
cost accounts show the profits available to shareholders and are the most
appropriate basis for presentation of the Group's balance sheet. Profit or loss
determined under the historical cost convention includes 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.
Revenue recognition
Revenues associated with the sale of oil, natural gas liquids, liquefied
natural gas, petroleum and chemical products and all other items are recognized
when the title passes to the customer. Generally, revenues from the production
of natural gas and oil properties in which the Group has an interest with other
producers, are recognized on the basis of the Group's working interest in those
properties (the entitlement method). Differences between the production sold and
the Group's share of production are not significant.
Foreign currencies
On consolidation, assets and liabilities of subsidiaries are translated
into US dollars at closing rates of exchange. Income and cash flow statements
are translated at average rates of exchange. Exchange differences resulting from
the retranslation of net investments in subsidiaries, 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.
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.
F-8
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (continued)
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.
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.
F-9
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (continued)
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.
Petroleum revenue tax
The charge for petroleum revenue tax is calculated using a
unit-of-production method.
Changes in unit-of-production factors
Changes in factors which affect unit-of-production calculations are dealt
with prospectively, not by immediate adjustment of prior years' amounts.
Environmental liabilities
Environmental expenditures that relate to current or future revenues are
expensed or capitalized as appropriate. Expenditures that relate to an existing
condition caused by past operations and that do not contribute to current or
future earnings are expensed.
Liabilities for environmental costs are recognized when environmental
assessments or clean-ups are probable and the associated costs can be reasonably
estimated. Generally, the timing of these provisions coincides with the
commitment to a formal plan of action or, if earlier, on divestment or on
closure of inactive sites. The amount recognized is the best estimate of the
expenditure required. Where the liability will not be settled for a number of
years the amount recognized is the present value of the estimated future
expenditure.
Leases
Assets held under leases which result in Group companies receiving
substantially all risks and rewards of ownership (finance leases) are
capitalized as tangible fixed assets at the estimated present value of
underlying lease payments. The corresponding finance lease obligation is
included with borrowings. Rentals under operating leases are charged against
income as incurred.
F-10
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 1 -- Accounting policies (concluded)
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.
Deferred taxation
Deferred taxation is calculated, using the liability method, in respect of
timing differences arising primarily from the difference between the accounting
and tax treatments of both depreciation and petroleum revenue tax. Provision is
made or recovery anticipated where timing differences are expected to reverse in
the foreseeable future.
Discounting
The unwinding of the discount on provisions is included within interest
expense. Any change in the amount recognized for environmental and other
provisions arising through changes in discount rates is included within interest
expense.
Comparative figures
Information for 2000 has been restated to reflect the transfer of the
natural gas liquids business from Refining and Marketing to Gas and Power. In
addition, certain prior year figures have been restated to conform with the 2001
presentation.
Note 2 -- Turnover
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Sales and operating revenue.......................... 208,299 168,709 91,891
Customs duties and sales taxes....................... 34,081 20,647 8,325
------ ------ ------
174,218 148,062 83,566
====== ====== ======
Note 3 -- Production taxes
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
UK petroleum revenue tax............................. 600 707 237
Overseas production taxes............................ 1,089 1,354 780
------ ------ ------
1,689 2,061 1,017
====== ====== ======
F-11
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 4 -- Distribution and administration expenses
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Distribution................................................ 9,852 7,514 5,031
Administration.............................................. 1,066 1,817 1,033
------ ------ ------
10,918 9,331 6,064
====== ====== ======
Distribution and administration expenses for 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,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Income from other fixed asset investments................... 208 202 66
Other interest and miscellaneous income..................... 486 603 348
------ ------ ------
694 805 414
====== ====== ======
Income from investments publicly traded included above...... 32 8 14
------ ------ ------
Note 6 -- Exceptional items
Exceptional items comprise profit (loss) on sale of fixed assets and
businesses or termination of operations and restructuring costs, as follows:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Profit on sale of businesses or
termination of operations -- Group........................ 182 341 427
-- Joint ventures............... -- -- 42
Loss on sale of businesses or
termination of operations -- Group........................ (250) (209) (106)
------ ------ ------
(68) 132 363
Profit on sale of fixed assets -- Group..................... 948 535 84
-- Joint ventures............ -- 24 --
Loss on sale of fixed assets -- Group..................... (343) (471) (784)
-- Associated undertakings... (2) -- --
------ ------ ------
603 88 (700)
------ ------ ------
535 220 (337)
Restructuring costs -- Group................................ -- -- (1,900)
-- Joint ventures....................... -- -- (43)
------ ------ ------
Exceptional items........................................... 535 220 (2,280)
Taxation (charge) credit:
Sale of businesses or termination of operations............. (50) (181) (21)
Sale of fixed assets........................................ (455) (111) (29)
Restructuring costs......................................... -- -- 280
------ ------ ------
Exceptional items, net of tax............................... 30 (72) (2,050)
====== ====== ======
F-12
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 6 -- Exceptional items (concluded)
Sales of businesses or termination of operations
The profit on the sale of businesses during 2001 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. For 1999 the
profit related mainly to the divestment by the Group of its Canadian oil
properties and certain chemicals businesses. These included the Verdugt acid
salts business; the Plaskon electronics materials business located in the USA
and Singapore; and the US Fibers and Yarns business. The profit on sale of
businesses by joint ventures in 1999 was mainly attributable to the disposal by
the BP/Mobil joint venture of its retail network in Hungary.
For 2001 the loss on sale of businesses or termination of operations
relates principally to 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. The loss during 1999 arose from the
closure of this joint venture.
Sale of fixed assets
The profit on the sale of fixed assets in 2001 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 profit on the sale of fixed assets in 1999 included the
Federal Trade Commission-mandated sale of distribution terminals and service
stations in the USA, the divestment by the Group of its interest in an olefins
cracker at Wilton in the UK and the sale and leaseback of US railcars.
The loss on sale of fixed assets in 2001 arises 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. The
major element of the loss in 1999 was the disposal by the Group of its interest
in the Pedernales oil field in Venezuela.
Additional information on the sale of businesses and fixed assets is given
in Note 18 -- Disposals.
Restructuring costs
These costs arose from restructuring activity across the Group following
the merger of BP and Amoco at the end of 1998 and relate predominantly to the
Group's US operations. The major elements of the restructuring charges comprise
employee severance costs ($1,212 million) and provisions to cover future rental
payments on surplus leasehold office accommodation and other property ($297
million). During 1999, some 16,000 employees left the Group through severance or
outsourcing arrangements. Also included in the restructuring charges are office
closure costs, contract termination payments and asset write-downs. The cash
outflow for these restructuring charges during 1999 was $976 million and during
2000 was $446 million.
F-13
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 7 -- Interest expense
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Bank loans and overdrafts............................ 119 154 119
Other loans (a)...................................... 1,111 1,221 854
Finance leases....................................... 78 107 75
------ ------ ------
1,308 1,482 1,048
Capitalized at 5% (2000 7% and 1999 6%).............. 81 119 43
------ ------ ------
Group................................................ 1,227 1,363 1,005
Joint ventures....................................... 70 78 70
Associated undertakings.............................. 135 140 131
Unwinding of discount on provisions ................. 196 189 130
Change in discount rate for provisions .............. 42 -- (20)
------ ------ ------
Total charged against profit......................... 1,670 1,770 1,316
====== ====== ======
----------
(a) Interest expense includes a charge of $62 million (2000 $111 million and
1999 $24 million) relating to early redemption of debt.
Note 8 -- Depreciation and amounts provided
Included in the income statement under the following headings:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Depreciation and amortization of goodwill and other intangibles
Replacement cost of sales.......................... 7,367 6,403 4,185
Distribution....................................... 1,221 707 408
Administration..................................... 94 87 115
Exceptional items.................................. -- -- 258
------ ------ ------
8,682 7,197 4,966
====== ====== ======
Depreciation of capitalized leased assets included above 65 79 70
------ ------ ------
Amounts provided against fixed asset investments
Exceptional items.................................. -- -- 84
Replacement cost of sales.......................... 68 252 (1)
------ ------ ------
68 252 83
====== ====== ======
The charge for depreciation and amortization of goodwill in 2001 includes
$175 million for the impairment of the Venezuelan Lake Maracaibo operation.
For 2000 the charge includes $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.
F-14
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 8 -- Depreciation and amounts provided (concluded)
The rationalization of office and other facilities in 1999 following the
merger resulted in the write-off of redundant IT and other office equipment and
furnishings. This charge of $258 million has been included within exceptional
items. In addition for 1999 the charge for depreciation includes $100 million
for the impairment of the Badami field in Alaska and $123 million for the
write-down of various Chemicals and Refining and Marketing assets.
In assessing the value in use of potentially impaired assets, a discount
rate of 9% has been used. This is the rate used by the Company for investment
appraisal.
Note 9 -- Taxation
Charge for taxation
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
United Kingdom corporation tax:
Current at 30.0% (2000 at 30.0% and 1999 at 30.25%) 1,666 1,505 875
Overseas tax relief................................ (678) (310) (363)
------ ------ ------
988 1,195 512
Deferred at 30.0% (2000 at 30.0% and 1999 at 30.0%) (48) 12 91
------ ------ ------
940 1,207 603
------ ------ ------
Overseas:
Current............................................ 3,846 3,704 1,143
Deferred........................................... (66) (124) 30
Joint ventures..................................... 94 57 5
Associated undertakings............................ 203 128 99
------ ------ ------
4,077 3,765 1,277
------ ------ ------
Taxation charge for the year......................... 5,017 4,972 1,880
====== ====== ======
Included in the charge for the year is a charge of $505 million (2000 $292
million charge and 1999 $230 million credit) relating to exceptional items.
F-15
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 9 -- Taxation (continued)
Reconciliation of the UK statutory tax rate to the effective tax rate of the
Group on replacement cost profit before exceptional items
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
(% of profit before tax)
United Kingdom statutory tax rate.............................. 30 30 30
Increase (decrease) resulting from:
Current year timing differences not provided
(including current year losses unrelieved/prior
year losses utilized)..................................... (6) (5) (10)
(Relief for inventory holding losses)/tax on
inventory holding gains.................................. (1) 1 2
Overseas taxes at higher rates............................... 8 7 5
Tax credits.................................................. (2) (4) --
Acquisition amortization..................................... 4 3 --
Other........................................................ (2) (3) 1
------ ------ ------
Effective tax rate on replacement cost profit
before exceptional items................................... 31 29 28
====== ====== ======
Further information presented in compliance with the requirements of FASB
Statement of Financial Accounting Standards No. 109 -- 'Accounting For Income
Taxes' is set out below.
Provisions for deferred taxation
Gross potential
Provisions liability
--------------- ---------------
Years ended December 31,
---------------------------------
2001 2000 2001 2000
------ ------ ------ ------
($ million)
Analysis of movements during the year:
At January 1........................................ 1,822 1,783 10,595 7,953
Exchange adjustments................................ (56) (139) (140) (287)
Acquisitions........................................ 3 323 3 1,404
Charge (credit) for the year........................ (114) (112) 1,244 1,564
Deletions/transfers................................. -- (33) -- (39)
------ ------ ------ ------
At December 31...................................... 1,655 1,822 11,702 10,595
====== ====== ====== ======
of which -- United Kingdom.......................... 1,055 1,141 2,071 2,181
-- Overseas................................ 600 681 9,631 8,414
====== ====== ====== ======
Analysis of provision:
Depreciation........................................ 2,527 2,641 12,672 11,384
Petroleum revenue tax............................... (383) (337) (383) (337)
Other timing differences............................ (489) (482) (587) (452)
------ ------ ------ ------
1,655 1,822 11,702 10,595
====== ====== ====== ======
If provision for deferred taxation had been made on the basis of the gross
potential liability, the overseas taxation charge for the year would have
increased by $1,358 million (2000 $1,676 million and 1999 $442 million).
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.
F-16
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 9 -- Taxation (concluded)
The Group has adopted Financial Reporting Standard No. 19 'Deferred Tax'
with effect from January 1, 2002. If this new standard had been applied to the
reported results for 2001, the tax charge for the year would have increased by
$1,358 million to $6,375 million. In addition, at December 31, 2001 there would
have been a reduction of $9,050 million in shareholders' funds and capital
employed. This represents the difference between the gross potential and the
restricted liability amounts for the Group shown above ($10,047 million net of
the additional goodwill arising on acquisitions in 2000 of $1,081 million) and
$84 million for joint ventures and associated undertakings.
Effective tax rate
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Analysis of profit before taxation:
United Kingdom....................................... 2,333 3,426 1,663
Overseas............................................. 10,767 13,508 5,363
------ ------ ------
13,100 16,934 7,026
====== ====== ======
Taxation............................................. 5,017 4,972 1,880
====== ====== ======
Effective tax rate................................... 38% 29% 27%
====== ====== ======
The following relates the United Kingdom statutory tax rate to the
effective tax rate of the Group based on profit before taxation:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
(% of profit before tax)
United Kingdom statutory tax rate.................... 30 30 30
Increase (decrease) resulting from:
Current year timing differences not provided....... (11) (5) (9)
(Prior year losses utilized) current
year losses unrelieved.......................... 4 2 2
(Inventory holding gains not taxed) no relief for
inventory holding losses..................... 3 (1) (5)
Overseas taxes at higher rates..................... 9 7 5
Tax credits........................................ (3) (4) --
Acquisition amortization .......................... 6 3 1
Other ............................................. -- (3) 3
------ ------ ------
Effective tax rate................................... 38 29 27
====== ====== ======
F-17
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 10 -- Dividends per ordinary share
Years ended December 31,
--------------------------------------------------------------
2001 2000 1999 2001 2000 1999 2001 2000 1999
------ ------ ------ ------ ------ ------ ------ ------ ------
(pence per share) (cents per share) ($ million)
First quarterly........... 3.665 3.220 3.069 5.25 5.00 5.00 1,178 1,133 970
Second quarterly.......... 3.911 3.352 3.112 5.50 5.00 5.00 1,235 1,128 970
Third quarterly........... 3.805 3.602 3.033 5.50 5.25 5.00 1,232 1,185 971
Fourth quarterly.......... 4.055 3.617 3.125 5.75 5.25 5.00 1,288 1,177 971
----- ----- ----- ----- ----- ----- ----- ----- -----
15.436 13.791 12.339 22.00 20.50 20.00 4,933 4,623 3,882
----- ----- ----- ----- ----- ----- ----- ----- -----
F-18
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 11 -- Profit per ordinary share
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
(cents per share)
Basic earnings per share....................................... 35.70 54.85 25.82
Diluted earnings per share..................................... 35.48 54.48 25.68
The calculation of basic earnings per ordinary share is based on the profit
attributable to ordinary shareholders, i.e. profit for the year less preference
dividends, related to the weighted average number of ordinary shares in issue
during the year. The profit attributable to ordinary shareholders is $8,008
million (2000 $11,868 million and 1999 $5,006 million). The average number of
shares outstanding excludes the shares held by the Employee Share Ownership
Plans.
The calculation of diluted earnings per share is based on profit
attributable to ordinary shareholders as for basic earnings per share. However,
the number of shares outstanding is adjusted to show the potential dilution if
employee share options are converted into ordinary shares. The number of
ordinary shares outstanding for basic and diluted earnings per share may be
reconciled as follows:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
(shares million)
Weighted average number of ordinary shares..................... 22,436 21,638 19,386
Ordinary shares issuable under employee share schemes.......... 138 145 111
------ ------ ------
22,574 21,783 19,497
====== ====== ======
In addition to basic earnings per share based on the historical cost profit
for the year, a further measure, based on replacement cost profit before
exceptional items, is provided as it is considered that this measure gives an
indication of underlying performance.
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
(cents per share)
Profit for the year......................................... 35.70 54.85 25.82
Inventory holding (gains) losses............................ 8.47 (3.36) (8.91)
------ ------ ------
Replacement cost profit for the year........................ 44.17 51.49 16.91
Exceptional items, net of tax............................... (0.14) 0.33 10.57
------ ------ ------
Replacement cost profit before exceptional items............ 44.03 51.82 27.48
====== ====== ======
F-19
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 12 -- Quarterly results of operations (unaudited)
Historical cost Profit (loss)
Group profit before Profit per ordinary
turnover interest and tax (loss) share
-------- ---------------- ------ ----------
($ million) (cents)
Year ended December 31, 2001
First quarter............................. 45,700 5,479 3,304 14.70
Second quarter............................ 48,689 5,183 3,171 14.12
Third quarter............................. 43,886 3,536 1,940 8.66
Fourth quarter............................ 37,114 572 (405) (1.78)
--------- -------------- ------- -----------
Total..................................... 175,389 14,770 8,010 35.70
========= ============== ======== ===========
Year ended December 31, 2000
First quarter............................. 33,091 4,336 3,085 15.88
Second quarter............................ 39,027 4,711 3,024 13.59
Third quarter............................. 44,862 5,377 3,351 14.85
Fourth quarter............................ 44,846 4,280 2,410 10.53
--------- -------------- ------- -----------
Total..................................... 161,826 18,704 11,870 54.85
========= ============== ======== ===========
Note 13 -- Rental expense under operating leases
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Minimum rentals:
Tanker charters.................................... 393 361 357
Plant and machinery................................ 530 471 509
Land and buildings................................. 355 343 271
------ ------ ------
1,278 1,175 1,137
Less: Rentals from sub-leases........................ (165) (185) (178)
------ ------ ------
1,113 990 959
====== ====== ======
Note 14 -- Research and development
Expenditure on research and development amounted to $385 million (2000
$434 million and 1999 $310 million).
F-20
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 15 -- Auditors' remuneration
Years ended December 31,
--------------------------------------------------
2001 2000 1999
--------------- --------------- ---------------
UK Total UK Total UK Total
------ ------ ------ ------ ------ ------
($ million)
Audit fees -- Ernst & Young:
Group audit......................... 5 13 6 15 6 14
Local statutory audit and
quarterly review 3 11 3 13 1 6
------ ------ ------ ------ ------ ------
8 24 9 28 7 20
====== ====== ====== ====== ====== ======
Fees for other services -- Ernst & Young
Acquisitions and disposals.......... 16 20 8 9 3 5
Taxation services................... 9 28 2 14 1 6
Assurance services.................. 4 11 5 10 4 5
Consultancy......................... -- -- 5 18 7 20
------ ------ ------ ------ ------ ------
29 59 20 51 15 36
====== ====== ====== ====== ====== ======
Group audit fees for 2000 include $1 million for excess of actual over
estimated fees for 1999.
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 assurance services in addition to
their statutory audit duties where their expertise and experience of BP are
important. Most of this work is of an audit nature. For the same reasons, it is
beneficial to the Group to use Ernst & Young for due diligence work relating to
acquisitions and disposals. 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.
Fees to major firms of accountants other than Ernst & Young for non-audit
services amounted to $305 million (2000 $275 million and 1999 $160 million).
Note 16 -- Currency exchange gains and losses
Accounted net foreign currency exchange loss included in the determination
of profit for the year amounted to $12 million (2000 $30 million gain and 1999
$17 million gain).
F-21
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 17 -- Acquisitions
2001 2000 1999
------------------------------------------------------- ----- -----
Fair value adjustments
------------------------
Accounting
Book value policy Fair Fair Fair
on acquisitions alignment Revaluations value value value
--------------- ------------ ------------ --------- ----- -----
($ million)
Intangible fixed assets............ 198 -- (4) 194 2,549 3
Tangible fixed assets.............. 386 87 368 841 21,768 119
Fixed assets -- investments........ 6 -- 12 18 4,085 9
Businesses held for resale......... -- -- -- -- 5,926 --
Current assets (excluding cash).... 402 2 24 428 6,759 10
Cash at bank and in hand........... -- -- -- -- 1,790 5
Finance debt....................... (55) -- -- (55) (7,942) (58)
Other creditors.................... (221) -- 7 (214) (7,193) (1)
Deferred taxation.................. (3) -- -- (3) (323) --
Other provisions................... (170) -- (1) (171) (3,254) --
Net investment in Erdoelchemie..... (170) -- -- (170) -- --
-------- -------- -------- -------- -------- --------
Net assets acquired................ 373 89 406 868 24,165 87
-------- -------- --------
Minority interests................. -- (1,840) --
Goodwill........................... 48 11,669 20
-------- -------- --------
Consideration...................... 916 33,994 107
======== ======== ========
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.
Pro forma effects as required by US GAAP are not presented as they would
not materially change reported consolidated results of operations.
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, $116 million, approximated the amount attributable
to the ARCO preference stock in the original determination of the consideration.
The fair values of the assets and liabilities of ARCO included in the
accounts for the year ended December 31, 2000 have been subject to further
investigation and review during 2001, as permitted by Financial Reporting
Standard No. 7 'Fair Values in Acquisition Accounting'. The revisions to the
previously reported fair values are set out below.
F-22
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 17 -- Acquisitions (concluded)
Fair value
as previously Final
reported Revisions fair value
------------- --------- ----------
($ million)
Intangible fixed assets.............................. 2,549 -- 2,549
Tangible fixed 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 fixed 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.
Acquisitions in 1999. During the year the Group acquired the oustanding 83%
of ProGas, a major Canadian natural gas supply aggregator, and 50% of Solarex, a
manufacturer and developer of photovoltaic products and systems, it did not
already own. Also in 1999 the Group purchased APEX, a solar electric company
based in Montpellier, France.
Note 18 -- Disposals
Divestments in 2001. During the year the Group made a number of disposals.
The major transactions 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.
F-23
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 18 -- Disposals (continued)
At December 31, 2000 the Foseco, Fosroc and Sericol speciality chemicals
businesses which were acquired as part of the Burmah Castrol acquisition were
categorized as businesses held for resale. Foseco was sold in July 2001, but the
other two businesses will now be retained and have been fully consolidated from
July 1, 2001.
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 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 $6,803
million. No profit or loss arose on these disposals.
Divestments in 1999. Disposals in 1999 included the sale of the Group's
Canadian oil properties; the divestment of its interest in the Pedernales oil
field in Venezuela; the Federal Trade Commission-mandated sale of distribution
terminals and service stations in the USA and certain chemicals activities.
These included the Verdugt acid salts business; its interest in an olefins
cracker at Wilton in the UK; the Plaskon electronics materials business located
in the USA and Singapore; the US Fibers and Yarns business; and the sale and
leaseback of US railcars. In addition the Group incurred a loss on the closure
of its paraxylene joint venture in Singapore.
Other major disposals during 2000 were the sale of the Group's common
interest in Altura Energy; the sale of the Alliance refinery; the divestment of
exploration and production interests in Trinidad, the UK, USA and Venezuela; and
the sale of the Southern Company Energy Marketing.
Total proceeds received for disposals represent the following amounts shown
in the cash flow statement:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Proceeds from the sale of businesses................. 538 8,333 1,292
Proceeds from the sale of fixed assets............... 2,365 3,029 1,149
------ ------ ------
2,903 11,362 2,441
====== ====== ======
F- 24
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 18 -- Disposals (concluded)
The disposals comprise the following:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Intangible assets.................................... 183 458 199
Tangible assets...................................... 1,481 3,224 2,340
Fixed asset -- investments........................... 898 673 206
Net assets of businesses held for resale............. 307 5,290 --
Current assets less current liabilities.............. (145) 919 175
Other provisions..................................... (112) 631 (94)
------ ------ ------
2,612 11,195 2,826
Profit (loss) on sale of businesses or
termination of operations.......................... (68) 132 321
Profit (loss) on sale of fixed assets................ 605 64 (700)
------ ------ ------
Total consideration.................................. 3,149 11,391 2,447
Increase in amounts receivable from disposals........ (246) (102) (12)
Cash retained........................................ -- 73 6
------ ------ ------
Net cash inflow...................................... 2,903 11,362 2,441
====== ====== ======
Note 19 -- Intangible assets
Exploration Other
expenditure Goodwill intangibles Total
---------- ---------- ---------- ----------
($ million)
Cost
At January 1, 2001..................... 6,106 12,055 755 18,916
Exchange adjustments................... (16) (116) (6) (138)
Acquisitions........................... 187 48 7 242
Additions.............................. 878 -- 92 970
Transfers.............................. (797) -- (35) (832)
Fair value adjustments................. -- 97 -- 97
Deletions.............................. (244) (93) (8) (345)
---------- ---------- ---------- ----------
At December 31, 2001................... 6,114 11,991 805 18,910
========== ========== ========== ==========
Depreciation
At January 1, 2001..................... 690 882 451 2,023
Exchange adjustments................... (6) (5) (1) (12)
Charge for the year.................... 238 1,180 61 1,479
Transfers.............................. (22) -- 11 (11)
Deletions.............................. (120) (37) (5) (162)
---------- ---------- ---------- ----------
At December 31, 2001................... 780 2,020 517 3,317
========== ========== ========== ==========
Net book amount
At December 31, 2001................... 5,334 9,971 288 15,593
At December 31, 2000................... 5,416 11,173 304 16,893
========== ========== ========== ==========
F- 25
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 20 -- Tangible assets
Property, plant and equipment:
Other of which:
Exploration Gas Refining businesses Assets
and and and and under
Production Power Marketing Chemicals corporate Total construction
----------- ----- --------- --------- ---------- ----- ------------
($ million)
Cost
At January 1, 2001.............. 93,025 1,820 30,280 14,898 1,984 142,007 6,439
Exchange adjustments............ (955) (57) (688) (285) (16) (2,001) (121)
Acquisitions.................... 47 3 -- 624 167 841 88
Additions....................... 7,525 251 2,247 1,017 350 11,390 6,922
Transfers....................... 797 (13) 25 (32) 259 1,036 (4,743)
Fair value adjustments.......... (911) -- -- -- -- (911) --
Deletions....................... (1,516) (61) (2,108) (432) (190) (4,307) (259)
------ ------ ------ ------ ------ ------ ------
At December 31, 2001............ 98,012 1,943 29,756 15,790 2,554 148,055 8,326
====== ====== ====== ====== ====== ======= ======
Depreciation
At January 1, 2001.............. 46,274 498 12,661 6,538 863 66,834
Exchange adjustments............ (543) (14) (289) (121) (6) (973)
Charge for the year............. 5,197 46 1,564 537 97 7,441
Transfers....................... 22 (6) 23 (12) 142 169
Deletions....................... (1,208) -- (1,106) (394) (118) (2,826)
------ ------ ------ ------ ------ ------
At December 31, 2001............ 49,742 524 12,853 6,548 978 70,645
====== ====== ====== ====== ====== ======
Net book amount
At December 31, 2001............ 48,270 1,419 16,903 9,242 1,576 77,410 8,326
At December 31, 2000............ 46,751 1,322 17,619 8,360 1,121 75,173 6,439
====== ====== ====== ====== ====== ======= ======
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, 2001....... 1,517 837 680 3,018 1,480 1,538
At December 31, 2000....... 1,926 1,076 850 2,946 1,395 1,551
====== ====== ====== ===== ===== =====
Leasehold land
--------------------
Over 50 years
Freehold land unexpired Other
------------- ------------- -----
($ million)
At December 31, 2001.................................. 2,279 211 170
At December 31, 2000.................................. 2,012 315 151
===== === ===
F - 26
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 21 -- Fixed assets -- investments
Associated undertakings
-------------------------
Share of
retained Joint Own Listed
Shares Loans profit ventures Loans shares(a) investments(b) Other(c) Total
------ ----- -------- -------- ----- ------ ----------- ----- -----
($ million)
Cost
At January 1, 2001....... 3,196 892 1,791 2,884 476 360 1,565 1,094 12,258
Exchange adjustments..... (23) (8) (62) (6) (28) (10) (39) 1 (175)
Additions and net movements
in joint ventures...... 237 340 (116) 683 30 33 -- 9 1,216
Acquisitions............. 13 -- -- -- 5 -- -- -- 18
Transfers................ 116 309 (91) 308 (284) -- -- (76) 282
Deletions................ (253) (253) (2) (8) (18) (117) (239) (30) (920)
------ ------ ------ ------ ------ ------ ------ ------ ------
At December 31, 2001 3,286 1,280 1,520 3,861 181 266 1,287 998 12,679
====== ====== ====== ====== ====== ====== ====== ====== ======
Amounts provided
At January 1, 2001...... 218 206 -- -- 43 -- -- 38 505
Exchange adjustments.... -- (5) -- -- -- -- -- 1 (4)
Provided in the year.... -- 37 -- -- 26 -- -- 5 68
Transfers............... -- 85 -- -- -- -- -- -- 85
Deletions............... -- (22) -- -- -- -- -- -- (22)
------ ------ ------ ------ ------ ------ ------ ------ ------
At December 31, 2001 218 301 -- -- 69 -- -- 44 632
====== ====== ====== ====== ====== ====== ====== ====== ======
Net book amount
At December 31, 2001 3,068 979 1,520 3,861 112 266 1,287 954 12,047
At December 31, 2000 2,978 686 1,791 2,884 433 360 1,565 1,056 11,753
====== ====== ====== ====== ====== ====== ====== ====== ======
----------
(a) Own shares are held in Employee Share Ownership Plans (ESOPs) to meet the
future requirements of the Employee Share Schemes (see Note 33) and prior
to award under the Long Term Performance Plan (see Note 34). At December
31, 2001 the ESOPs held 34,005,910 shares (45,514,664 shares at December
31, 2000) for the Employee Share Schemes and 7,673,056 shares (9,506,839
shares at December 31, 2000) for the Long Term Performance Plan. The market
value of these shares at December 31, 2001 was $323 million ($443 million
at December 31, 2000).
(b) The market value of listed investments at December 31, 2001 was $1,284
million.
(c) Other investments are unlisted.
Note 22 -- Inventories
December 31,
---------------
2001 2000
------ ------
($ million)
Petroleum................................................... 5,176 6,933
Chemicals................................................... 953 1,046
Other....................................................... 568 504
------ ------
6,697 8,483
Stores...................................................... 934 751
------ ------
7,631 9,234
====== ======
Replacement cost............................................ 7,686 9,392
====== ======
F - 27
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 23 -- Receivables
December 31, 2001 December 31, 2000
----------------- -----------------
Within After Within After
1 year 1 year(a) 1 year 1 year(a)
------ ------ ------ ------
($ million)
Trade receivables.................................. 15,436 -- 17,813 --
====== ====== ====== ======
Other receivables:
Joint ventures................................... 8 -- 39 --
Associated undertakings.......................... 260 49 98 46
Prepayments and accrued income................... 2,143 789 2,137 486
Taxation recoverable............................. 335 8 412 --
Pension prepayment............................... -- 3,539 -- 3,609
Other............................................ 3,806 296 3,309 469
------ ------ ------ ------
6,552 4,681 5,995 4,610
====== ====== ====== ======
Provisions for doubtful debts deducted from Trade receivables amounted to
$290 million ($357 million at December 31, 2000).
----------
(a) See Note 43-- US generally accepted accounting principles.
Note 24 -- Current assets -- investments
December 31,
---------------
2001 2000
------ ------
($ million)
Publicly traded -- United Kingdom..................................... 49 59
-- Foreign............................................ 30 220
------ ------
79 279
Not publicly traded.................................................... 371 382
------ ------
450 661
====== ======
Stock exchange value of publicly traded investments.................... 88 280
====== ======
Note 25 -- Finance debt
December 31, 2001 December 31, 2000
----------------- -----------------
Within After Within After
1 year 1 year 1 year 1 year
------ ------ ------ ------
($ million)
Bank loans and overdrafts.......................... 371(a) 409 895(a) 1,035
Other loans........................................ 8,647(a) 10,349 5,420(a) 11,916
------ ------ ------ ------
Total borrowings................................... 9,018 10,758 6,315 12,951
Obligations under capital leases................... 72 1,569 103 1,821
------ ------ ------ ------
9,090 12,327 6,418 14,772
====== ====== ====== ======
---------------
(a) Amounts due within one year include current maturities of long-term debt.
F - 28
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 25 -- Finance debt (continued)
Where a borrowing is swapped into another currency, the borrowing is
accounted in the swap currency and not in the original currency of denomination.
Total borrowings include $264 million ($369 million at December 31, 2000) 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 $1,768 million (December 31, 2000 $1,671 million)
with maturity periods ranging up to 36 years. They are classified as repayable
within one year, as required under UK GAAP, as the bondholders typically have
the option to tender these bonds for repayment on interest reset dates. Any
bonds that are tendered are usually remarketed and BP has not experienced any
significant repurchases. BP considers these bonds to represent long-term funding
when assessing the maturity profile of its borrowings.
At December 31, 2001, the Group's share of third party borrowings of joint
ventures and associated undertakings was $460 million and $1,136 million
respectively. These amounts are not reflected in the Group's debt on the balance
sheet.
Analysis of borrowings by year of repayment
December 31, 2001 December 31, 2000
------------------------------- ------------------------------
Bank loans Bank loans
and Other and Other
overdrafts loans Total overdrafts loans Total
---------- --------- --------- ---------- -------- ---------
($ million)
Due after 10 years........ 42 3,176 3,218 258 3,296 3,554
Due within 6-10 years...... -- 3,222 3,222 26 3,402 3,428
5 years......... 150 501 651 24 1,202 1,226
4 years......... 24 1,542 1,566 417 744 1,161
3 years......... 15 626 641 75 1,187 1,262
2 years......... 178 1,282 1,460 235 2,085 2,320
--------- --------- --------- --------- --------- ---------
409 10,349 10,758 1,035 11,916 12,951
1 year.......... 371 8,647 9,018 895 5,420 6,315
--------- --------- --------- --------- --------- ---------
780 18,996 19,776 1,930 17,336 19,266
========= ========= ========= ========= ========= =========
Amounts included above repayable by instalments part of which falls due
after five years from December 31, are as follows:
December 31,
---------------
2001 2000
------ ------
($ million)
After five years............................................ 120 27
Within five years........................................... 1,071 216
------ ------
1,191 243
====== ======
Interest rates on borrowings repayable wholly or partly more than five
years from December 31, 2001 range from 1% to 12% with a weighted average of 6%.
The weighted average interest rate on finance debt is 5%.
At December 31, 2001 the Group had substantial amounts of undrawn borrowing
facilities available, including committed facilities of $3,400 million expiring
in 2002 ($3,450 million at December 31, 2000 expiring in 2001). These facilities
are with a number of international banks and borrowings under them would be at
pre-agreed rates. Certain of these facilities support the Group's commercial
paper programme.
F - 29
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 25 -- Finance debt (continued)
Analysis of borrowings by currency
December 31,
December 31, 2001 2000
----------------------------------------------------------------- -----------
Fixed rate debt Floating rate debt
-------------------------------- -------------------
Weighted Weighted Weighted
average average time average
interest for which interest
rate rate is fixed Amount rate Amount Total Total
-------- ------------- ------ -------- ------ ----- -----
(%) (Years)($ million) (%) ($ million)($ million) ($ million)
US dollars............ 7 8 11,485 2 7,842 19,327 18,525
Sterling.............. -- -- -- 4 133 133 449
Other currencies...... 10 29 122 6 194 316 292
-------- -------- ------- -------
Total loans........... 11,607 8,169 19,776 19,266
======== ======== ======= =======
The Group aims for a balance between floating and fixed interest rates and,
in 2001, the proportion of floating rate debt was in the range 32-43% 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 borrowings and hedges described above, it is estimated that a change of
1% in the general level of interest rates on January 1, 2002 would change 2002
profit before tax by approximately $100 million.
Fair values and carrying amounts of borrowings
December 31,
----------------------------------------------
2001 2000
---------------------- ----------------------
Carrying Carrying
Fair value amount Fair value amount
---------- -------- ---------- --------
($ million)
Short-term borrowings.................... 5,185 5,185 3,706 3,706
Long-term borrowings..................... 14,875 14,360 15,573 15,299
--------- --------- --------- ---------
Total borrowings......................... 20,060 19,545 19,279 19,005
========= ========= ========= =========
The fair value and carrying amounts of borrowings shown above exclude the
effects of currency swaps, interest rate swaps and forward contracts (which are
included for presentation in the balance sheet). Long-term borrowings in the
above table include debt which matures in the year from December 31, 2001,
whereas in the balance sheet long-term debt of current maturity is reported
under amounts falling due within one year. Long-term borrowings also include US
Industrial Revenue/Municipal Bonds classified on the balance sheet as repayable
within one year. The carrying amount of the Group's short-term borrowings, which
mainly comprise commercial paper, bank loans and overdrafts, approximate their
fair value. The fair value of the Group's long-term borrowings is estimated
using quoted prices or, where these are not available, discounted cash flow
analyses, based on the Group's current incremental borrowing rates for similar
types and maturities of borrowing.
F - 30
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 25 -- Finance debt (continued)
Obligations under capital leases
The future minimum lease payments together with the present value of the
net minimum lease payments were as follows:
December 31,
2001
-------------
($ million)
2002 ............................................................... 97
2003 ............................................................... 159
2004 ............................................................... 165
2005 ............................................................... 173
2006 ............................................................... 177
Thereafter........................................................... 2,877
-----------
3,648
Less: amount representing lease interest............................. 2,007
-----------
Present value of net minimum capital lease payments.................. 1,641
===========
of which -- due within one year...................................... 72
-- due after one year....................................... 1,569
-----------
The following information is presented in compliance with the requirements
of US GAAP.
Bank loans and overdrafts and other loans-- long term
Weighted average December 31,
interest rate at ---------------
December 31, 2001 2001 2000
----------------- ------ ------
(%) ($ million)
US dollar................................. 7 10,617 12,599
Sterling.................................. 6 19 289
Other currencies.......................... 10 122 63
----- -----
10,758 12,951
===== =====
Bank loans and overdrafts and other loans -- short term
December 31,
---------------
2001 2000
------ ------
($ million)
Current maturities of long-term debt........................ 1,993 938
Commercial paper............................................ 4,634 2,943
Bank loans and overdrafts................................... 371 762
Other....................................................... 2,020 1,672
------ ------
9,018 6,315
====== ======
F - 31
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 25 -- Finance debt (concluded)
Weighted average
interest rate
at December 31,
----------------
2001 2000
------ ------
(%)
Commercial paper............................................ 2 7
Bank loans, overdrafts and other borrowings................. 4 8
US Industrial Revenue/Municipal bonds....................... 2 5
Note 26 -- Accounts payable and accrued liabilities
December 31, 2001 December 31, 2000
----------------- -----------------
Within After Within After
1 year 1 year 1 year 1 year
------ ------ ------ ------
($ million)
Trade payables...................................... 13,129 -- 14,363 --
====== ====== ====== ======
Other accounts payable and accrued liabilities:
Joint ventures..................................... 21 -- 67 --
Associated undertakings............................ 268 4 296 4
Production taxes................................... 254 1,346 347 1,123
Taxation on profits................................ 3,456 -- 4,091 2
Social security.................................... 63 -- 59 --
Accruals and deferred income....................... 4,843 1,029 6,557 1,876
Dividends.......................................... 1,289 -- 1,178 --
Other.............................................. 5,201 707 5,152 837
------ ------ ------ ------
15,395 3,086 17,747 3,842
====== ====== ====== ======
Note 27 -- Other provisions
Unfunded Other
pension postretirement
Decommissioning Environmental plans benefits Other Total
--------------- ------------- ------- -------------- ----- -----
($ million)
At January 1, 2001...... 3,001 2,131 1,579 2,726 1,536 10,973
Exchange adjustments.... (66) (5) (63) -- (14) (148)
Acquisitions............ -- 33 114 -- 24 171
New provisions.......... 156 180 230 160 438 1,164
Unwinding of discount... 104 77 -- -- 15 196
Change in discount rate. 315 37 -- -- 5 357
Utilized/deleted........ (206) (355) (117) (222) (331) (1,231)
------ ------ ------ ------ ------ -------
At December 31, 2001.... 3,304 2,098 1,743 2,664 1,673 11,482
====== ====== ====== ====== ====== =======
F - 32
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 27 -- Other provisions (concluded)
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, 2001 the provision for
the costs of decommissioning these production facilities and pipelines at the
end of their economic lives was $3,304 million ($3,001 million at December 31,
2000). The provision has been estimated using existing technology, at current
prices and discounted using a real discount rate of 3% (2000 3.5%). 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 of and timing of
incurring these costs.
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,
2001 was $2,098 million ($2,131 million at December 31, 2000). The provision has
been estimated using existing technology, at current prices and discounted using
a real discount rate of 3% (2000 3.5%). These costs are expected to be incurred
over the next 10 years. The extent and cost of future remediation programs 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 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 3% (2000 3.5%).
Note 28 -- 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 between floating rate and
fixed rate debt. The Group also manages certain of its exposures to movements in
oil and natural gas prices. The underlying economic currency of the Group's cash
flows is mainly the US dollar. Accordingly, most of our borrowings are in US
dollars, are hedged with respect to the US dollar or swapped into US dollars.
Significant non-dollar cash flow exposures are hedged. Gains and losses arising
on these hedges are deferred and recognized in the income statement or as
adjustments to carrying amounts, as appropriate, only when the hedged item
occurs. In addition, we trade derivatives in conjunction with these risk
management activities. The results of trading are recognized in income in the
current period.
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 borrowing, 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.
BP is exposed to financial risks, including market risk, credit risk and
liquidity risk, arising from the Group's normal business activities. These risks
and the Group's approach to dealing with them are discussed below.
F - 33
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Market risk
Market risks include 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 financial and commodity
instruments, including derivatives. We also trade derivatives in conjunction
with these risk management activities.
Currency exchange rates. Fluctuations in exchange rates can have
significant effects on the Group's 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.
The main underlying economic currency of the Group's cash flows is the US
dollar and the Group's borrowings are predominantly in US dollars. Our foreign
exchange management policy is to minimize economic and material transactional
exposures 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.
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 2001, the proportion of floating rate debt was in the range
32-43% of total net debt outstanding.
Oil and natural gas prices. BP's trading units use 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.
Market risk management and trading. 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, cash flow or transaction being hedged. By contrast, where
derivatives are held for trading purposes, changes in market risk factors give
rise to realized and unrealized gains and losses, which are recognized in the
current period.
F - 34
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
All financial instrument and derivative activity, whether for risk
management or trading, is carried out by specialist teams which have the
appropriate skills, experience and supervision. These teams are subject to close
financial and management control, meeting generally accepted industry practice
and reflecting the principles of the Group of Thirty Global Derivatives Study
recommendations. 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. As part of its approach to ensuring that
control over trading is maintained to a high and consistent standard, the
Group's business units dealing in the oil, natural gas and financial markets
were brought together within a single integrated supply and trading organization
during 2001.
Credit risk
Credit risk is the potential exposure of the Group to loss in the event of
non-performance by a counterparty. The credit risk arising from the Group's
normal commercial operations is controlled by individual operating units within
guidelines. In addition, as a result of its use of financial and commodity
instruments, including derivatives, to manage market risk, the Group has credit
exposures through its dealings in the financial and specialized oil and natural
gas markets. The Group controls the related credit risk by entering into
contracts only with highly credit-rated counterparties and through credit
approvals, limits and monitoring procedures, and does not usually require
collateral or other security. Counterparty credit validation, independent of the
dealers, is undertaken before contractual commitment.
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, 2001, the Group had available undrawn committed
facilities of $3,400 million ($3,450 million at December 31, 2000). These
committed facilities, which are mainly with a number of international banks,
expire in 2002. The Group expects to renew the facilities on an annual basis.
With the exception of the table of currency exposures shown on page F-38,
short-term debtors and creditors which arise directly from the Group's
operations have been excluded from the disclosures contained in this note, as
permitted by FRS No. 13 `Derivatives and Other Financial Instruments:
Disclosures'.
F - 35
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Interest rate risk
The interest rate and currency profile of the financial liabilities of the
Group at December 31, 2001, after taking into account the effect of interest
rate swaps, currency swaps and forward contracts, is set out below.
Fixed rate Floating rate Interest free
------------------------------------ ----------------- ---------------------
Weighted Weighted Weighted Weighted
average average time average average time
interest for which interest until
rate rate is fixed Amount rate Amount maturity Amount Total
------------- ------------- ------ -------- ------ ------------ ------ ------
(%) (Years) ($ million) (%) ($ million) (Years) ($ million) ($ million)
At December 31, 2001
US dollar............... 7 8 11,624 2 10,143 4 1,528 23,295
Sterling................ -- -- -- 4 133 3 114 247
Other currencies........ 10 29 122 6 194 2 334 650
------- ------- ------- -------
11,746 10,470 1,976 24,192
======= ======= ======= =======
At December 31, 2000
US dollar........... 7 9 10,506 6 10,674 4 2,155 23,335
Sterling............ -- -- -- 6 449 6 147 596
Other currencies.... 8 30 45 10 247 2 532 824
------- ------- ------- -------
10,551 11,370 2,834 24,755
======= ======= ======= =======
December 31,
---------------
2001 2000
------ ------
($ million)
Analysis of the above liabilities by balance sheet caption:
Current liabilities -- falling due within one year
-- Finance debt................................................... 9,090 6,418
Noncurrent liabilities
-- Finance debt................................................... 12,327 14,772
-- Accounts payable and accrued liabilities....................... 1,673 2,501
Provisions for liabilities and charges
-- Other provisions............................................... 1,102 1,064
------- -------
24,192 24,755
======= =======
F - 36
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
The financial liabilities upon which interest is paid comprise principally
borrowings and net obligations under finance leases. The financial liabilities
which are interest free comprise various accruals, sundry creditors and
provisions relating to the Group's normal commercial operations with payment
dates spread over a number of years.
In managing its finance debt, the Group aims for a balance between floating
and fixed interest rates and, in 2001, the proportion of floating rate debt was
in the range of 32-43% of total net debt outstanding. Interest rate swaps and
futures are used by the Group to modify the interest characteristics of its
long-term borrowings from a fixed to a floating rate basis or vice versa. The
following table indicates the types of instruments used and their weighted
average interest rates.
December 31,
---------------
2001 2000
------ ------
($ million except percentages)
Receive fixed rate swaps -- notional amount........... 999 2,310
Average receive fixed rate ........................... 5.6% 6.4%
Average pay floating rate............................. 2.3% 6.7%
Pay fixed rate swaps -- notional amount............... 2,914 3,125
Average pay fixed rate................................ 6.6% 6.7%
Average receive floating rate......................... 2.3% 6.7%
Futures contracts -- notional amount.................. 760 --
Average pay fixed rate................................ 2.7% --
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 Weighted
average average time average average time
interest for which interest until
rate rate is fixed Amount rate Amount maturity Amount Total
------------- ------------- ------ -------- ------ ------------ ------ ------
(%) (Years) ($ million) (%) ($ million) (Years) ($ million) ($ million)
At December 31, 2001
US dollar........... 3 1 92 2 574 2 2,269 2,935
Sterling............ 7 2 81 4 11 2 762 854
Other currencies.... 5 1 181 5 264 1 192 637
------- ------- ------- -------
354 849 3,223 4,426
======= ======= ======= =======
At December 31, 2000
US dollar........... 4 1 226 5 1,127 2 1,502 2,855
Sterling............ 8 2 81 5 74 2 803 958
Other currencies.... 6 1 115 6 593 3 942 1,650
------- ------- ------- -------
422 1,794 3,247 5,463
======= ======= ======= =======
December 31,
---------------
2001 2000
------ ------
($ million)
Analysis of the above financial assets by balance sheet caption:
Fixed assets -- investments....................................... 2,353 3,054
Current assets
--Receivables -- amount falling due after more than one year...... 265 578
--Investments..................................................... 450 661
--Cash at bank and in hand........................................ 1,358 1,170
------- -------
4,426 5,463
======= =======
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 - 37
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Maturity profile of financial liabilities
The profile of the maturity of the financial liabilities included in the
Group's balance sheet is shown in the table below.
December 31,
---------------
2001 2000
------ ------
($ million)
Due within:1 year.................................... 9,090 6,418
1 to 2 years.............................. 2,159 3,834
2 to 5 years.............................. 3,656 4,456
Thereafter................................ 9,287 10,047
------ ------
24,192 24,755
====== ======
Foreign exchange rate risk
The table below shows the Group's principal currency exposures arising from
normal trading activities. These exposures give rise to net currency gains and
losses recognized in the profit and loss account. Such exposures comprise the
monetary assets and monetary liabilities of the Group that are not denominated
in the functional currency of the operating unit involved. As at December 31,
2001 and 2000, these exposures were as shown below.
Net foreign currency monetary assets (liabilities)
-------------------------------------------------
US dollar Sterling Euro Other Total
--------- -------- -------- -------- --------
($ million)
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)
======== ======== ======== ======== ========
At December 31, 2000
US dollar.............................. -- (555) 313 (534) (776)
Sterling............................... 487 -- 498 269 1,254
Other.................................. 584 189 (9) (231) 533
-------- -------- -------- -------- --------
1,071 (366) 802 (496) 1,011
======== ======== ======== ======== ========
F - 38
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
In accordance with its policy for managing its foreign exchange rate risk,
the Group enters into various types of foreign exchange contracts, such as
currency swaps, forwards and options. The fair values and carrying amounts of
these derivatives are shown in the fair value disclosures below.
Fair values of financial assets and liabilities
The estimated fair value of the Group's financial instruments is shown in
the table below. The table also shows the 'net carrying amount' of the financial
asset or liability. This amount represents the net book value, i.e. market value
when acquired or later marked to market. The carrying amounts and fair values of
finance debt shown below exclude the effects of interest rate swaps, currency
swaps and forward contracts (which are included for presentation in the balance
sheet). Current maturities of long-term finance debt are included under
long-term borrowings.
December 31,
-------------------------------------------------------------------------------
2001 2000
------------------------------------- -------------------------------------
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.................... 2,350 2,353 2,882 3,054
Current assets
-- Other receivables -- amounts falling
due after more than one year............... 265 265 578 578
-- Investments................................. 459 450 662 661
-- Cash at bank and in hand.................... 1,358 1,358 1,170 1,170
Finance debt
-- Short-term borrowings....................... (5,185) (5,185) (3,706) (3,706)
-- Long-term borrowings........................ (14,875) (14,360) (15,573) (15,299)
-- Net obligations under finance leases........ (1,619) (1,608) (1,831) (1,816)
Noncurrent liabilities
-- Accounts payable and accrued liabilities.... (1,673) (1,673) (2,501) (2,501)
Provisions for liabilities and charges -- other
provisions................................... (1,102) (1,102) (1,064) (1,064)
Derivative financial or commodity instruments
Risk management -- interest rate contracts.... (139) -- (49) --
-- foreign exchange contracts. (251) (264) (338) (369)
-- oil price contracts........ -- -- 4 4
-- natural gas price contracts (259) (259) 31 12
Trading -- interest rate contracts.... -- -- -- --
-- foreign exchange contracts. (3) (3) -- --
-- oil price contracts........ 26 26 36 36
-- natural gas price contracts 12 12 24 24
F - 39
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Interest rate contracts include futures contracts, swap agreements and
options. Foreign exchange contracts include forward and futures contracts, swap
agreements and options. Oil and natural gas price contracts are those which
require settlement in cash and include futures contracts, swap agreements and
options and cash-settled commodity instruments (derivative commodity contracts
that permit settlement either by delivery of the underlying commodity or in
cash) such as forward contracts.
The following methods and assumptions were used by the Group in estimating
its fair value disclosures for its financial instruments:
Fixed assets -- Investments: The carrying amount reported in the balance
sheet for unlisted fixed asset investments approximates their fair value. The
fair value of listed fixed asset investments has been determined by reference to
market prices.
Current assets -- 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 or commodity instruments: 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.
Risk management
Gains and losses on derivatives used for risk management purposes are
deferred and recognized in earnings or as adjustments to carrying amounts, as
appropriate, when the underlying debt matures or the hedged transaction occurs.
When an anticipated transaction is no longer likely to occur or finance debt is
terminated before maturity, any deferred gain or loss that has arisen on the
related derivative is recognized in the income statement, together with any gain
or loss on the terminated item. Where such derivatives used for hedging purposes
are terminated before the underlying debt matures or the hedged transaction
occurs, the resulting gain or loss is recognized on a basis which matches the
timing and accounting treatment of the underlying hedged item. The unrecognized
and carried-forward gains and losses on derivatives used for hedging, and the
movements therein, are shown in the following table.
F - 40
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Unrecognized Carried forward in the balance sheet
----------------------- ------------------------------------
Gains Losses Total Gains Losses Total
----- ------ ----- ----- ------ -----
($ million)
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)
Gains and losses at January 1, 2000............. 236 (215) 21 65 (283) (218)
of which accounted for in income in 2000...... 54 (60) (6) 32 (45) (13)
Trading activities
The Group maintains active trading positions in a variety of derivatives.
This activity is undertaken in conjunction with risk management activities.
Derivatives held for trading purposes are marked to market and any gain or loss
recognized in the income statement. For traded derivatives, many positions have
been neutralized, with trading initiatives being concluded by taking opposite
positions to fix a gain or loss, thereby achieving a zero net market risk.
The following table shows the fair value at December 31, 2001 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.
Years ended December 31,
---------------------------------------------------
2001 2000
------------------------- ------------------------
Year end Year end Year end Year end
fair value fair value fair value fair value
asset liability asset liability
---------- ---------- ---------- ----------
($ million)
Interest rate contracts................... -- -- -- --
Foreign exchange contracts................ 14 (17) 10 (10)
Oil price contracts....................... 248 (222) 159 (123)
Natural gas price contracts............... 799 (787) 1,288 (1,264)
-------- -------- -------- --------
1,061 (1,026) 1,457 (1,397)
======== ======== ======== ========
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.
F - 41
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
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 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.
Years ended December 31,
----------------------------------------------------------------------------------
2001 2000
------------------------------------- -------------------------------------
High Low Average Year end High Low Average Year end
----- ----- ------- -------- ----- ----- ------- --------
($ million)
Interest rate trading........... 1 -- -- -- 2 -- 1 --
Foreign exchange trading........ 3 -- 1 -- 15 -- 1 1
Oil price trading............... 29 10 18 17 23 4 13 13
Natural gas price trading....... 21 4 10 9 16 1 6 13
The presentation of trading results shown in the table below includes
certain activities of BP's trading units which involve 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 the
classification of the gain or loss on such derivatives along with the gain or
loss arising from the physical and paper trades to which they relate,
representing the net result of the trading portfolio.
Year ended December 31,
--------------------------------------
2001 2000
-------------------------- --------
Natural Net gain Net gain
Oil gas (loss) (loss)
----- ------- -------- --------
($ million)
Derivative financial and commodity instruments... 419 (129) 290 94
Physical trades.................................. 265 405 670 549
------ ------ ------ ------
Total trading............................. 684 276 960 643
Interest rate trading..................... 1 1
Foreign exchange trading.................. 81 52
------ ------
1,042 696
====== ======
The following information is presented in compliance with the requirements
of FASB Statement of Accounting Standards No. 105 -- 'Disclosure of Information
about Financial Instruments with Off-Balance-Sheet Risk and Financial
Instruments with Concentrations of Credit Risk', No. 107 -- 'Disclosure about
Fair Value of Financial Instruments', No. 119 -- 'Disclosures about Derivative
Financial Instruments and Fair Value of Financial Instruments' and No. 133 --
'Accounting for Derivative Instruments and Hedging Activities'.
The Group's accounting policies under UK GAAP do not satisfy the criteria
for hedge accounting under SFAS 133. The Group does not intend to modify its
practice under UK GAAP. See Note 43 - US generally accepted accounting
principles.
F - 42
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Further information on accounting policies
The following information is presented in amplification of the accounting
policies presented in Note 1 -- Accounting policies.
Reporting in the income statement
Gains and losses on oil price contracts held for trading and for risk
management purposes and natural gas price contracts held for trading purposes
are reported in cost of sales in the income statement in the period in which the
change in value occurs. Gains and losses on interest rate or foreign currency
derivatives used for trading are reported in other income and cost of sales,
respectively. Gains and losses in respect of derivatives used to manage interest
rate exposures are recognized as adjustments to interest expense.
Where derivatives are used to convert non-US dollar borrowing into US
dollars, the gains and losses are deferred and recognized on maturity of the
underlying debt, together with the matching loss or gain on the debt. The two
amounts offset each other in the income statement.
Gains and losses on derivatives identified as hedges of significant non-US
dollar firm commitments or anticipated transactions are not recognized until the
hedged transaction occurs. The treatment of the gain or loss arising on the
designated derivative reflects the nature and accounting treatment of the hedged
item. The gain or loss is recorded in cost of sales in the income statement or
as an adjustment to carrying values in the balance sheet, as appropriate.
Gains and losses arising from natural gas price derivatives are recognized
in earnings when the hedged transaction occurs. The gains or losses are reported
as components of the related transactions.
Reporting in the balance sheet
The carrying amounts of foreign exchange contracts that hedge finance debt
are included within finance debt in the balance sheet. The carrying amounts of
other derivatives, including option premiums paid or received, are included in
the balance sheet under receivables or payables within current assets and
current liabilities respectively, as appropriate.
Cash flow effects
Interest rate swaps give rise, at specified intervals, to cash settlement
of interest differentials. Under currency swaps the counterparties initially
exchange a principal amount in two currencies, agreeing to re-exchange the
currencies at a future date at the same exchange rate. The Group's currency
swaps have terms of up to eight years.
Interest rate futures require an initial margin payment and daily
settlement of margin calls. Interest rate forwards require settlement of the
interest rate differential on a specified future date. Currency forwards require
purchase or sale of an agreed amount of foreign currency at a specified exchange
rate at a specified future date, generally over periods of up to one year for
the Group. Currency options involve the initial payment or receipt of a premium
and will give rise to delivery of an agreed amount of currency at a specified
future date if the option is exercised.
F - 43
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
For oil and natural gas price futures and options traded on regulated
exchanges, BP meets initial margin requirements by bank guarantees and daily
margin calls in cash. For swaps and over-the-counter options, BP settles with
the counterparty on conclusion of the pricing period.
In the statement of cash flows the effect of interest rate derivatives is
reflected in interest paid. The effect of foreign currency derivatives used for
hedging non-US dollar debt is included under financing. The cash flow effects of
foreign currency derivatives used to hedge non-US dollar firm commitments and
anticipated transactions are included in net cash inflow from operating
activities for items relating to earnings or in capital expenditure or
acquisitions, as appropriate, for items of a capital nature. The cash flow
effects of all oil and natural gas price derivatives and all traded derivatives
are included in net cash inflow from operating activities.
Fair value of financial instruments
The carrying amounts and fair values of finance debt are as follows:
December 31,
---------------------------------------------
2001 2000
--------------------- ---------------------
Carrying Fair Carrying Fair
amount value amount value
asset asset asset asset
(liability) (liability) (liability) (liability)
--------- --------- --------- ---------
($ million)
Finance debt
Long-term............................... (14,360) (14,875) (15,299) (15,573)
Short-term.............................. (5,185) (5,185) (3,706) (3,706)
Cash at bank and in hand.................. 1,358 1,358 1,170 1,170
The carrying amounts of foreign exchange contracts that hedge finance debt
are included within finance debt in the balance sheet. The carrying amounts of
other derivatives are included in the balance sheet under receivables or
payables as appropriate.
In addition to the above financial instruments, the Group has issued third
party guarantees and indemnities amounting to $275 million ($454 million at
December 31, 2000). The credit risk and maximum cash requirement of these
guarantees and indemnities is the full contractual amount, however no material
loss is expected to arise.
F - 44
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
The table shows the 'fair value' of the asset or liability created by
derivatives. This represents the market value at the balance sheet date. Credit
exposure at December 31 is represented by the column 'fair value asset'.
The table also shows the 'net carrying amount' of the asset or liability
created by derivatives. This amount represents the net book value. While the
gross contract or notional amounts give an indication of the scale of business
transacted, they do not represent the Group's aggregate exposure to market or
credit risk.
Gross Net carrying
contract Fair value Fair value amount asset
amount asset liability (liability)
--------- ---------- ---------- ------------
($ million)
At December 31, 2001
Risk management
Interest rate contracts........ 4,673 18 (157) --
Foreign exchange contracts..... 9,628 80 (331) (264)
Oil price contracts............ 230 3 (3) --
Natural gas price contracts.... 4,619 91 (350) (259)
Trading
Interest rate contracts........ 791 -- -- --
Foreign exchange contracts..... 2,283 14 (17) (3)
Oil price contracts............ 33,076 248 (222) 26
Natural gas price contracts.... 48,774 799 (787) 12
At December 31, 2000
Risk management
Interest rate contracts........ 5,435 54 (103) --
Foreign exchange contracts..... 8,132 114 (452) (369)
Oil price contracts............ 434 19 (15) 4
Natural gas price contracts.... 2,614 147 (116) 12
Trading
Interest rate contracts........ -- -- -- --
Foreign exchange contracts..... 2,434 10 (10) --
Oil price contracts............ 6,316 159 (123) 36
Natural gas price contracts.... 36,206 1,288 (1,264) 24
Interest rate contracts include futures contracts, swap agreements and
options. Foreign exchange contracts include forward and futures contracts, swap
agreements and options. Oil and natural gas price contracts are those which
require settlement in cash and include futures contracts, swap agreements and
options.
F - 45
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Interest rate risk management
The Group enters into interest rate contracts to manage its cost of
borrowing as indicated in the following table:
December 31, 2001 December 31, 2000
----------------------------- -----------------------------
Gross Fair Fair Gross Fair Fair
contract value value contract value value
amount asset liability amount asset liability
-------- ------- --------- ------- ------- ---------
($ million)
Swaps ....................... 3,913 18 (157) 5,435 54 (103)
Futures...................... 760 -- -- -- -- --
------- ------- ------- ------- ------- -------
4,673 18 (157) 5,435 54 (103)
======= ======= ======= ======= ======= =======
Interest rate swaps allow BP to modify the interest characteristics of its
long-term borrowings from a fixed to a floating rate basis or vice versa. Under
interest rate swaps, the Group agrees with other parties to exchange, at
specified intervals, the interest differentials calculated by reference to an
agreed notional principal amount. There is no exchange of the underlying
principal amount.
Interest rate futures contracts are used by the Group, on occasion, in
preference to interest rate swaps to achieve a more cost effective method of
managing the mix between fixed and floating rate debt. These contracts are
commitments to either purchase or sell designated financial instruments at a
future date for a specified price, and may be settled in cash or through
delivery. The Group may hold highly liquid contracts, such as US Treasury bond
futures and Eurodollar futures, with terms ranging up to two years. Initial
margin requirements and daily calls are met either by the deposit of securities
or in cash. Futures contracts have little credit risk as regulated exchanges are
the counterparties.
The following table indicates the types of instruments used and their
weighted average interest rates. Average variable rates are based on the actual
rates in place at December 31; these may change significantly, affecting future
cash flows. Swap contracts mainly have maturities between one and ten years.
December 31,
-----------------------------
2001 2000
--------- ---------
($ million, except percentages)
Receive -- fixed swaps -- notional amount.......... 999 2,310
Average receive fixed rate......................... 5.6% 6.4%
Average pay floating rate.......................... 2.3% 6.7%
Pay -- fixed swaps -- notional amount.............. 2,914 3,125
Average pay fixed rate............................. 6.6% 6.7%
Average receive floating rate...................... 2.3% 6.7%
Futures contracts -- notional amount............... 760 --
Average pay fixed rate............................. 2.7% --
Interest rate forward contracts, which include forward rate agreements and
options on forward rate agreements, may also be used by the Group to manage
interest rate risk on debt. These contracts are agreements which allow the
interest rate cost on a principal amount to be fixed for a specified period
commencing on a future date.
F - 46
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Swaptions may also be employed to manage interest rate risk on debt. A
swaption is an agreement that conveys the right, but not the obligation, to swap
a series of fixed rate interest payments for floating rate interest payments, or
vice versa, at a given future point in time. Typically the swaptions entered
into by the Group are cash settled at expiry.
Foreign exchange risk management
The Group enters into various types of foreign exchange contracts in
managing its foreign exchange risk as indicated in the following table:
December 31, 2001 December 31, 2000
------------------------------- ------------------------------
Gross Fair Fair Gross Fair Fair
contract value value contract value value
amount asset liability amount asset liability
--------- --------- --------- --------- --------- ---------
($ million)
Currency swaps............... 1,789 12 (247) 2,441 15 (303)
Forwards..................... 7,839 68 (84) 5,691 99 (149)
Options...................... -- -- -- -- -- --
--------- --------- --------- --------- --------- ---------
9,628 80 (331) 8,132 114 (452)
========= ========= ========= ========= ========= =========
The Group's foreign exchange management policy is to minimize economic
exposures from currency movements against the US dollar. This is achieved by
raising finance in US dollars, hedging with respect to the US dollar or swapping
into US dollars and hedging significant non-dollar cash flows. Examples of
significant non-dollar cash flows are sterling-based capital lease payments,
sterling tax payments, sterling dividend payments and capital expenditure and
operational requirements of Exploration in the UK.
Under currency swaps the counterparties initially exchange a principal
amount in two currencies, agreeing to re-exchange the currencies at a future
date and at the same exchange rate. In addition, interest payments in the
respective currencies are exchanged at specified intervals over the term of the
agreement. The Group's currency swaps have terms up to eight years. The majority
of the Group's currency swaps relate to major currencies such as Sterling,
Euros, Swiss Francs, Canadian Dollars and Japanese Yen.
Currency forward contracts are commitments to purchase or sell an agreed
amount of foreign currency at a specified exchange rate at a specified future
date.
Currency options may be used from time to time. They are normally directly
negotiated and allow, but do not require, the holder to buy from or sell to the
writer an agreed amount of currency at a specified exchange rate within a stated
period, and involve the initial payment or receipt of a premium. The Group's
option contracts have an average term of less than one year. There were no
option contracts outstanding at December 31, 2001 and 2000.
Currency options may include cylinder option contracts. A cylinder is the
purchase of an option to buy foreign currency and the simultaneous selling of an
option to sell the same amount of foreign currency to BP at a different exchange
rate. The effect is to limit the risk of both gain and loss. This is achieved at
little or no cost as the symmetry of the options means that the premium paid for
one option is balanced by the premium received from the sale of the other.
F - 47
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (continued)
Oil and natural gas price risk management
The Group enters into various types of oil and natural gas price contracts
to manage its exposure to some movements in hydrocarbon prices as indicated in
the following table. Contracts which are capable of being settled by delivery of
oil, oil products or natural gas are excluded.
December 31, 2001 December 31, 2000
------------------------------- -------------------------------
Gross Fair Fair Gross Fair Fair
contract value value contract value value
amount asset liability amount asset liability
--------- --------- --------- --------- --------- ----------
($ million)
Oil
Swaps................. 123 2 (3) 239 13 (13)
Options............... 4 1 -- 6 1 (1)
Futures............... 103 -- -- 189 5 (1)
--------- --------- --------- --------- --------- ---------
230 3 (3) 434 19 (15)
========= ========= ========= ========= ========= =========
Natural gas
Swaps................. 3,494 85 (339) 2,511 133 (114)
Options............... 1,090 6 (11) 7 10 (2)
Futures............... 35 -- -- 96 4 --
--------- --------- --------- --------- --------- ---------
4,619 91 (350) 2,614 147 (116)
========= ========= ========= ========= ========= =========
The Group uses swaps, options and futures to hedge future purchases and
sales of crude oil and refined oil products. The term of the oil price
derivatives is usually less than one year. Natural gas swaps, options and
futures are used to convert specific sales and purchase contracts from fixed
prices to market prices. Swaps are also used to hedge exposure for price
differentials between locations. The term of most natural gas price derivatives
is less than one year, with some having terms of two years.
Under swaps, BP agrees with other parties to pay or receive the difference
between a fixed and variable price at a range of specified dates determined by
reference to an agreed notional volume.
The option and futures contracts are traded on regulated exchanges.
Exchange-traded options allow, but do not require, the holder to either buy from
or sell to the writer an agreed amount of futures contracts at a specified price
at a specified future date. Futures are fixed price commitments to purchase or
sell a contract, whose value is derived from the price of oil at a specified
future date. Initial margin requirements and daily cash settlements for both
these types of contracts are met either by bank guarantees or in cash. There is
little credit risk under these contracts as regulated exchanges are the
counterparties.
Trading activities
The Group maintains active trading positions in a variety of derivatives.
This activity is undertaken in conjunction with risk management. Derivatives
held for trading purposes are marked to market and any gain or loss recognized
in the income statement. For traded derivatives, many positions have been
neutralized, with trading initiatives being concluded by taking opposite
positions to fix a gain or loss, thereby achieving a zero net market risk.
F - 48
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 28 -- Derivative financial instruments (concluded)
The following table discloses the contract or notional amount and fair
value of the derivatives held for trading purposes at December 31, 2001 and 2000
and the average fair value for the year.
Year ended December 31, 2001 Year ended December 31, 2000
------------------------------- ---------------------------------
Net Average Net Average
Gross fair value fair value Gross fair value fair value
contract asset asset contract asset asset
amount (liability) (liability) amount (liability) (liability)
--------- --------- --------- -------- ----------- -----------
($ million)
Interest rate contracts
Futures..................... 791 -- -- -- -- --
Options..................... -- -- -- -- -- --
Swaptions................... -- -- -- -- -- --
--------- --------- --------- --------- --------- ---------
791 -- -- -- -- --
========= ========= ========= ========= ========= =========
Foreign exchange contracts
Forwards.................... 2,037 (3) (4) 2,388 (1) (3)
Options..................... 246 -- -- 46 1 --
--------- --------- --------- --------- --------- ---------
2,283 (3) (4) 2,434 -- (3)
========= ========= ========= ========= ========= =========
Oil price contracts
Swaps....................... 5,560 20 27 3,549 35 1
Futures..................... 911 -- -- 1,985 -- --
Options..................... 26,605 6 7 782 1 3
--------- --------- --------- --------- --------- ---------
33,076 26 34 6,316 36 4
========= ========= ========= ========= ========= =========
Natural gas price contracts
Swaps....................... 15,454 (15) 23 36,129 40 19
Futures..................... 150 -- -- -- (12) (4)
Options..................... 33,170 27 26 77 (4) --
--------- --------- --------- --------- --------- ---------
48,774 12 49 36,206 24 15
========= ========= ========= ========= ========= =========
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 - 49
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 29 -- Capital and reserves
Paid
Share in Merger Other Retained
capital surplus reserve reserves earnings Total
-------- -------- -------- --------- --------- -----
($ million)
At January 1, 2001.................... 5,653 3,770 26,869 456 36,668 73,416
Exchange adjustment................... -- -- -- -- (908) (908)
Employee share schemes................ 8 118 -- -- -- 126
ARCO.................................. 7 51 114 (117) -- 55
Redemption of ARCO preference shares.. -- -- -- (116) -- (116)
Share buyback......................... (39) 39 -- -- (1,281) (1,281)
Qualifying Employee Share
Ownership Trust (QUEST)............. -- 36 -- -- (36) --
Profit for the year................... -- -- -- -- 8,010 8,010
Dividends............................. -- -- -- -- (4,935) (4,935)
--------------------------------------------------------
At December 31, 2001.................. 5,629 4,014 26,983 223 37,518 74,367
========================================================
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 33,460,856 ordinary shares were
issued under the BP, Amoco and Burmah Castrol employee share schemes.
ARCO. 10,728,978 ordinary shares were issued in connection with the
conversion of ARCO preference shares and a further 13,069,008 ordinary shares
were issued in respect of ARCO employee share option schemes.
Redemption of ARCO preference shares. A cash tender offer was made in March
2001 for the outstanding ARCO preference shares.
Share buyback. The Company purchased for cancellation 153,928,949 ordinary
shares for a total consideration of $1,281 million.
Note 30 -- Retained earnings
Retained earnings of $37,518 million ($36,668 million at December 31, 2000)
include the following amounts, the distribution of which is limited by statutory
or other restrictions:
December 31,
---------------
2001 2000
------ ------
($ million)
Parent company....................................................... 15,547 17,547
Subsidiary undertakings.............................................. 8,994 9,120
Joint ventures and associated undertakings........................... 1,345 1,042
------ ------
25,886 27,709
====== ======
Cumulative net exchange losses of $4,790 million are included in retained
earnings ($3,882 million losses at December 31, 2000).
There were no unrealized currency translation differences for the year on
long-term borrowings used to finance equity investments in foreign currencies
(2000 nil and 1999 nil).
F - 50
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 31 -- Analysis of consolidated statement of cash flows
(i) Reconciliation of historical cost profit before interest and tax to net
cash inflow from operating activities
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Historical cost profit before interest and tax........... 14,770 18,704 8,342
Depreciation and amounts provided........................ 8,750 7,449 4,965
Exploration expenditure written off...................... 238 264 304
Share of profits of joint ventures
and associated undertakings............................ (1,194) (1,853) (1,704)
Interest and other income................................ (478) (360) (217)
(Profit) loss on sale of fixed assets and businesses
or termination of operations............................. (537) (196) 379
Charge for provisions.................................... 1,008 702 847
Utilization of provisions................................ (1,119) (969) (597)
Decrease (increase) in inventories....................... 1,490 (1,449) (1,562)
Decrease (increase) in debtors........................... 1,989 (5,587) (4,013)
(Decrease) increase in payables.......................... (2,508) 3,711 3,546
------ ------ ------
Net cash inflow from operating activities................ 22,409 20,416 10,290
====== ====== ======
(ii) Exceptional items
The cash outflow in 2000 in respect of the restructuring costs charged in
1999 was $446 million (1999 $976 million). The cash outflow in 1999 relating to
the merger expenses charged in 1998 was $166 million. Both amounts were included
in the net cash inflow from operating activities.
(iii) Financing
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Long-term borrowing.................................. (1,296) (1,680) (2,140)
Repayments of long-term borrowing.................... 2,602 2,353 2,268
Short-term borrowing................................. (6,257) (4,120) (3,136)
Repayments of short-term borrowing................... 4,823 4,821 2,299
----- ------ ------
(128) 1,374 (709)
Issue of ordinary share capital...................... (181) (257) (245)
Share buyback........................................ 1,281 2,001 --
Stamp duty reserve tax............................... -- 295 --
----- ------ ------
Net cash outflow (inflow) ........................... 972 3,413 (954)
===== ====== ======
(iv) Management of liquid resources
Liquid resources comprise current asset investments which are principally
commercial paper issued by other companies. The net cash inflow from the
management of liquid resources was $211 million (2000 $452 million outflow and
1999 $93 million inflow).
F - 51
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 31 -- Analysis of consolidated statement of cash flows (concluded)
(v) Commercial paper
Net movements in commercial paper are included within short-term borrowings
or repayment of short-term borrowings as appropriate.
(vi) Movement in net debt
Years ended December 31,
------------------------------------------------------------------------------------------
2001 2000
-------------------------------------------- --------------------------------------------
Current Current
Finance asset Net Finance asset Net
debt Cash investments debt debt Cash investments debt
------- ------- ----------- ------- ------- ------- ----------- -------
($ million)
At January 1.......... (21,190) 1,170 661 (19,359) (14,544) 1,331 220 (12,993)
Exchange adjustments.. (8) (53) -- (61) 96 (39) (11) 46
Acquisitions.......... (55) -- -- (55) (8,072) -- -- (8,072)
Net cash flow......... (128) 241 (211) (98) 1,374 (122) 452 1,704
Other movements....... (36) -- -- (36) (44) -- -- (44)
------ ------ ------ ------ ------ ------ ------- -------
At December 31........ (21,417) 1,358 450 (19,609) (21,190) 1,170 661 (19,359)
====== ====== ====== ====== ====== ====== ======= =======
Note 32 -- Operating lease commitments
Annual commitments under operating leases were as follows:
December 31,
-----------------------------------------------
2001 2000
---------------------- ----------------------
Land and Land and
buildings Other buildings Other
--------- --------- --------- ---------
($ million)
Expiring within: 1 year.................. 28 313 41 181
2 to 5 years............ 115 306 54 330
Thereafter.............. 184 113 235 220
--------- --------- --------- ---------
327 732 330 731
========= ========= ========= =========
The minimum future lease payments (after deducting related rental income
from operating sub-leases of $580 million) were as follows:
December 31,
2001
------------
($ million)
2002 ............................................................... 958
2003 ............................................................... 729
2004 ............................................................... 573
2005 ............................................................... 515
2006 ............................................................... 465
Thereafter........................................................... 2,626
---------
5,866
=========
F - 52
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 33 -- Employee share schemes
BP offers most of its employees the opportunity to acquire a shareholding
in the company through savings-related and matching share plan arrangements.
Such arrangements are now in place in over 60 countries. BP also uses long-term
performance plans (see Note 34) and the granting of share options as elements of
remuneration for executive directors and senior employees.
During 2001 share options were granted to the executive directors under the
Executive Directors' Long Term Incentive Plan (EDLTIP) and to certain other
categories of employees. For these options the option price was the market price
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. The options are exercisable
between the third and the tenth anniversary of the date of grant.
Share options were also granted in 2001 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 scheme)
employees save monthly over a three- or five-year period towards the purchase of
shares at a price fixed when the option is granted. The option price is usually
set at a 20% discount to the market price at the time of grant. The option must
be exercised within six months of maturity of the savings contract; otherwise it
lapses. The plan is run in the UK and a small number of other countries.
For 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 40 other
countries.
The Company sponsors a number of savings plans covering most US employees.
Under these plans, employees may contribute up to 18% of their salary subject to
certain regulatory limits. Typically the employee receives a dollar-for-dollar
company matched contribution for the first 7% of eligible pay contributed to
most of these plans on a before-tax or after-tax basis, or a combination of
both. The precise arrangement depends on the individual's employment contract.
Company contributions are initially invested in BP ADS funds, but employees may
transfer those amounts and may invest their own contributions in more than 200
investment options. The Company's contributions vest over a period of five
years. Company contributions to savings plans during the year were $125 million
($101 million).
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 2001 the ESOP released 11,508,754 shares (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, 2001 the ESOP held 34,005,910
shares (2000, 45,514,664 shares).
F - 53
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 33 -- Employee share schemes (continued)
BP has established a Qualifying Employee Share Ownership Trust (QUEST) to
support the UK ShareSave plan. During the year, contributions of $36 million
($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.
At December 31, 2001, all the 8,148,640 ordinary shares issued to the QUEST
had been transferred to employees exercising options under the UK ShareSave
plan.
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
(options thousands)
Employee share options granted during the year:
Savings related schemes............................ 7,901 7,930 8,828
BP Share Option Plan............................... 58,208 50,461 41,054
------ ------ ------
66,109 58,391 49,882
====== ====== ======
The exercise prices for BP options granted during the year were
(pound)5.11/$7.36 (7,900,810 options) for savings-related and similar schemes
and (pound)5.72/$8.23 (weighted average price) for 58,207,741 options granted
under the share option plan.
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
(shares thousands)
Shares issued in respect of options exercised during the year:
Savings related schemes...................................... 8,842 13,709 12,176
BP, Amoco and Burmah Castrol executive share option plans.... 24,619 23,280 51,472
------ ------ ------
33,461 36,989 63,648
====== ====== ======
In 2001 11,508,754 shares (2000, 9,412,931 shares and 1999, 8,779,000
shares) were released from the ESOP for matching share plans. In 2000, 1,123,000
shares and 1999, 2,514,000 shares were issued to the ESOP.
F - 54
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 33 -- Employee share schemes (continued)
2001 2000 1999
------ ------ ------
(shares thousands)
Options outstanding at December 31:
BP options ............................................ 370,550 342,509 323,161
Exercise period........................................ 2002-2011 2001-2010 2000-2009
Price (pound).......................................... 1.29-6.40 1.29-6.40 1.29-6.23
Price (dollar)......................................... 2.77-9.97 2.77-9.97 2.77-9.97
Share option transactions under employee share schemes are summarized as
follows:
Years ended December 31,
----------------------------------------------------------------------
2001 2000 1999
-------------------- --------------------- -------------------
Weighted Weighted Weighted
average average average
Number of exercise Number of exercise Number of exercise
shares price shares price shares price
--------- -------- --------- -------- --------- --------
($) ($) ($)
Outstanding at January 1.... 342,509,046 5.61 323,161,387 4.95 346,897,822 4.34
Burmah Castrol.............. -- -- 3,293,317 5.02 -- --
Reinstated.................. 7,152 7.84 3,729 2.94 37,480 5.24
Granted..................... 66,108,551 8.13 58,390,883 8.17 49,882,128 7.88
Exercised................... (33,592,964) 3.97 (37,029,467) 3.76 (63,711,433) 3.85
Stock appreciation rights
exercised................. -- -- -- -- (542,772) 3.30
Cancelled................... (4,481,516) 7.37 (5,310,803) 6.72 (9,401,838) 5.54
-------------- -------------- --------------
Outstanding at December 31.. 370,550,269 6.18 342,509,046 5.61 323,161,387 4.95
============== ============== ==============
Exercisable at December 31.. 241,268,277 229,987,199 206,116,577
============== ============== ==============
Available for grant at
December 31.............. 1,185,523,186 1,234,983,212 1,087,626,398
============== ============== ==============
Options outstanding at December 31, 2001 will be exercisable between 2002
and 2011.
F - 55
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 33 -- Employee share schemes (concluded)
For the share options outstanding and exercisable at December 31, 2001 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 - $4.46................. 77,538,865 2.11 3.55 77,126,053 3.54
$4.51 - $5.49................. 82,106,458 5.01 5.10 72,961,042 5.15
$5.54 - $7.98................. 114,558,374 5.69 6.93 71,427,330 6.67
$8.02 - $9.97................. 96,346,572 8.76 8.33 19,753,852 8.29
---------- --------- -------- ----------- --------
370,550,269 5.59 6.18 241,268,277 5.34
========== ========= ======== =========== ========
As allowed by SFAS 123 `Accounting for Stock-Based Compensation' the
Company has elected to continue to follow Accounting Principles Board Opinion
No. 25, 'Accounting for Stock Issued to Employees'. In accordance with this
accounting statement the Company does not recognize compensation expense on the
grant of the options. Had compensation expense been determined based upon the
fair value of the stock options at grant date consistent with the method of SFAS
123, the Company's profit for the year and profit per ordinary share for 2001
would have been reduced by $126 million (2000 $122 million and 1999 $65 million)
and 1 cent (2000 1 cent and 1999 1 cent), respectively.
The weighted average fair value of BP share options granted in 2001 was
$2.05 (2000 $2.33 and 1999 $2.27). The fair value of each option grant was
estimated on the date of grant using a Black-Scholes option pricing model with
the following assumptions for 2001, 2000 and 1999, respectively; risk-free
interest rates of 5.0%, 6.0% and 6.5%; dividend yield of 3%; expected lives of
one, two, three or five years as appropriate and volatility of 26%, 33% and 32%.
F - 56
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 34 -- Long Term Performance Plan
During 2001 the Company operated two long-term performance plans: the
Executive Directors' Long Term Incentive Plan (EDLTIP) for executive directors
and the Long Term Performance Plan (LTPP) for senior executives. Prior to 2000
the executive directors also participated in the LTPP. 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 2001 in respect of the 1998-2000 LTPP.
The cost of potential future awards for both the EDLTIP and LTPP are
accrued over the three-year performance periods of each plan. The amount charged
in 2001 was $80 million (2000 $119 million). The value of awards under the
1998-2000 LTPP made in 2001 was $61 million (1997-99 LTPP $78 million).
Employee Share Ownership Plans (ESOPs) have been established to acquire BP
shares to satisfy any awards made to participants under the EDLTIP and LTPP and
then to hold them for the participants during the retention period of the plan.
In order to hedge the cost of potential future awards the ESOPs may, from time
to time over the performance period of the plans, purchase BP shares in the open
market. The Company provides funding to the ESOPs. The assets and liabilities of
the ESOPs are recognized as assets and liabilities of the Company within these
accounts. The ESOPs have waived their rights to dividends on shares held for
future awards.
At December 31, 2001 the ESOPs held 7,673,056 shares (2000, 9,506,839
shares) for potential future awards.
Note 35 -- Directors' remuneration
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Total for all directors
Emoluments..................................................... 17 14 13
Ex gratia payment.............................................. -- 1 6
Non-executive directors retiring in 2001....................... 1 -- --
Gains made on the exercise of share options.................... -- 3 5
Amounts awarded under long-term incentive schemes.............. 17 15 8
====== ====== ======
Highest paid director
Emoluments..................................................... 4 3 2
Gains made on the exercise of share options.................... -- -- 5
Amount awarded under long-term incentive schemes............... 4 4 --
Accrued pension at December 31................................. 1 1 1
====== ====== ======
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 - 57
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 35 -- Directors' remuneration (continued)
Pension contributions
Five executive directors participate in a non-contributory pension scheme
established for UK staff by a separate trust fund to which contributions are
made by BP based on actuarial advice. There were no contributions to this
pension scheme in 2001, 2000 and 1999. Two US executive directors participated
in the BP Retirement Accumulation Plan.
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 crystallized 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 the use of office and basic secretarial facilities following
their retirement. The cost involved in doing so is not significant.
Note 36 -- Loans to officers
Miss J C Hanratty has a low interest loan of $43,000 made to her prior to
her appointment as Company Secretary on October 1, 1994.
F - 58
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 37 -- Employee costs and numbers
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Employee costs
Wages and salaries................................... 6,740 6,071 5,302
Social security costs................................ 474 410 359
Pension costs........................................ 427 187 (97)
------ ------ ------
7,641 6,668 5,564
====== ====== ======
At December 31,
------------------------
2001 2000 1999
------ ------ ------
Number of employees
Exploration and Production........................... 16,550 16,000 12,500
Gas and Power........................................ 1,950 1,600 1,400
Refining and Marketing (a)........................... 64,600 67,100 44,650
Chemicals............................................ 21,950 17,600 18,700
Other businesses and corporate....................... 5,100 4,900 3,150
------- ------- -------
110,150 107,200 80,400
======= ======= =======
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
Average number of employees
Year ended December 31, 2001
Exploration and Production............. 3,550 750 5,700 6,200 16,200
Gas and Power.......................... 550 100 600 550 1,800
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......... 1,400 500 2,250 900 5,050
-------- -------- -------- -------- --------
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 and Power.......................... 550 50 600 300 1,500
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......... 1,100 400 2,400 700 4,600
-------- -------- -------- -------- --------
18,200 19,400 41,600 18,800 98,000
======== ======== ======== ======== ========
Year ended December 31, 1999
Exploration and Production............. 3,500 850 5,100 5,500 14,950
Gas and Power.......................... 450 50 600 300 1,400
Refining and Marketing (b)............. 9,600 10,050 20,300 7,950 47,900
Chemicals.............................. 4,100 4,900 9,850 2,000 20,850
Other businesses and corporate......... 1,150 350 1,000 500 3,000
-------- -------- -------- -------- --------
18,800 16,200 36,850 16,250 88,100
======== ======== ======== ======== ========
---------------
(a) 1999 includes 18,050 employees assigned to the BP/Mobil joint venture.
(b) Includes 7,800 employees assigned to the BP/Mobil joint venture in the UK
and 9,650 employees in the Rest of Europe.
F - 59
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 38 -- Pensions
Most Group companies have pension plans, the forms and benefits of which
vary with conditions and practices in the countries concerned. Pension benefits
may be provided 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' final pensionable salary and
length of service. Defined benefit plans may be externally funded or unfunded.
The assets of funded plans are generally held in separately administered trusts.
Contributions to funded defined benefit plans are based on advice from
independent actuaries using actuarial methods, the objective of which is to
provide adequate funds to meet pension obligations as they fall due. No
contributions were made to the UK and US pension funds during 2001. It is not
expected that any contributions will be made in 2002. For unfunded plans, where
assets are not held with the specific purpose of matching pension obligations
the accrued liability for pension benefits is included within other provisions.
The majority of the Group's employees are members of defined benefit schemes.
The principal plans are reviewed annually by the independent actuaries and
subject to a formal actuarial valuation every three years. The date of the
latest actuarial valuation for the UK and US plans was January 1, 2001 and for
the unfunded plans in Europe was January 1, 2002.
Pension costs for the principal plans have been derived using the projected
unit credit method and by amortizing surpluses and deficits on a straight line
basis over the average expected remaining service lives of the current
employees. The main assumptions used in calculating the credit/charge for the
principal plans were as follows:
Years ended December 31,
----------------------------------------------
2001 2000 1999
---------- ---------- ----------
UK plans:
Rate of return on assets............ 6.5% 6.5% 6.0%
Discount rate....................... 6.5% 6.5% 6.0%
Future salary increases............. 5.0% 5.0% 4.5%
Future pension increases............ 3.0% 3.0% 2.5%
Dividend growth..................... n/a n/a n/a
Other European plans:
Rate of return on assets............ n/a n/a n/a
Discount rate....................... 6.2% 6.2% 6.4%
Future salary increases............. 3.2% 3.2% 3.4%
Future pension increases............ 2.1% 2.1% 2.3%
Dividend growth..................... n/a n/a n/a
US plans:
Rate of return on assets............ 10.0% 10.0% 10.0%
Discount rate....................... 7.5% 7.5% 6.5%
Future salary increases............. 4.0% 4.0% 4.0%
Future pension increases............ nil nil nil
Dividend growth..................... n/a n/a n/a
----------
n/a = not applicable
F - 60
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 38 -- Pensions (continued)
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Principal plans:
Service cost -- benefits earned during year........ 397 364 347
Interest cost on projected benefit obligation...... 1,309 1,211 999
Expected return on plan assets..................... (1,717) (1,625) (1,273)
Amortization of transition asset................... (66) (72) (83)
Recognized net actuarial gain...................... (169) (203) (108)
Recognized prior service cost...................... 74 78 17
Curtailment and settlement (gains) losses.......... 36 (119) (150)
Special termination benefits....................... 175 233 3
------ ------ ------
39 (133) (248)
Other defined benefit plans.......................... 73 38 30
Defined contribution schemes......................... 155 220 121
------ ------ ------
Total pension expense (income)....................... 267 125 (97)
====== ====== ======
At January 1, 2001, the date of the latest actuarial valuations, the market
value and actuarial value of assets in the Group's major externally funded
pension plans in the UK and the USA was $26,587 million ($25,520 million at
January 1, 2000) and $24,121 million ($20,474 million at January 1, 2000)
respectively. The actuarial value of the assets of these plans represented 128%
(2000 130%) of the benefits that had accrued to members of those plans, after
allowing for expected future increases in salaries.
At December 31, 2001 the obligation for accrued benefits in respect of the
major unfunded schemes in Europe was $1,510 million ($1,438 million at December
31, 2000). Of this amount, $1,317 million ($1,167 million at December 31, 2000)
has been provided in these accounts.
The Group continues to account for pensions in accordance with Statement of
Standard Accounting Practice No. 24 'Accounting for Pension Costs'. A new
standard (Financial Reporting Standard No. 17 'Retirement Benefits') which
changes the basis of accounting for pensions and other postretirement benefits
will be adopted by the Group for its reporting for the year ended December 31,
2003. This new standard requires certain additional disclosures in accounting
periods prior to its implementation. The additional disclosures for the year
ended December 31, 2001 are set out below.
-------------------------
Other
UK European USA
----- -------- -----
Major assumptions as at December 31, 2001
(%)
Rate of increase in salaries................................ 4.5 3.2 4.0
Rate of increase to pensions in payment..................... 2.5 2.0 --
Rate of increase to deferred pensions....................... 2.5 2.0 --
Discount rate for scheme liabilities........................ 6.0 6.2 7.25
Inflation................................................... 2.5 2.0 3.0
F - 61
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 38 -- Pensions (continued)
The expected long-term rates of return and market values of the assets of
the significant defined benefit plans at December 31, 2001 were as follows:
UK Other European USA
---------------------- ------------------- ---------------------
Expected Expected Expected
long-term long-term long-term
rate of Market rate of Market rate of Market
return value return value return value
--------- --------- --------- --------- --------- ----------
(%) ($ million) (%) ($ million) (%) ($ million)
Market value of assets
at December 31, 2001
Equities...................... 7.5 12,228 n/a -- 11.0 4,537
Bonds......................... 5.5 2,449 n/a -- 7.0 942
Property...................... 6.5 1,057 n/a -- 8.0 51
Cash.......................... 4.5 1,146 n/a -- 4.0 95
------- ------- -------
16,880 -- 5,625
Present value of scheme liabilities 12,746 1,510 (6,146)
------- ------- -------
Surplus (deficit) in the plans 4,134 (1,510) (521)
Deferred tax.................. (1,240) 422 193
------- ------- -------
2,894 (1,088) (328)
======= ======= =======
F - 62
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 38 -- Pensions (concluded)
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.
Other
UK European USA
---------------- ---------------- ----------------
2001 2000 2001 2000 2001 2000
------ ------ ------ ------ ------ ------
($ million)
Benefit obligation at January 1 13,213 11,077 1,438 1,513 5,546 3,827
Service cost................ 255 225 12 10 130 129
Interest cost............... 811 746 89 86 409 380
Plan amendments............. -- 809 -- -- 16 --
Curtailments, settlements and
special termination benefits -- -- -- -- 208 191
Actuarial (gain) loss....... (646) 626 (42) 44 536 40
Acquisitions................ -- 1,241 189 -- 101 2,308
Plan participants' contributions 26 24 -- -- -- --
Settlement payments......... -- -- -- -- (9) (423)
Benefit payments............ (546) (563) (101) (94) (791) (906)
Exchange adjustment......... (367) (972) (75) (121) -- --
------ ------ ------ ------ ------ ------
Benefit obligation at December 31 12,746 13,213 1,510 1,438 6,146 5,546
------ ------ ------ ------ ------ ------
Fair value of plan assets at January 1 19,617 20,189 -- -- 6,970 5,331
Actual return on plan assets (1,689) 216 -- -- (682) (118)
Acquisitions................ -- 1,344 -- -- 91 2,817
Plan participants' contributions 26 24 -- -- -- --
Employer contributions...... 27 14 -- -- 46 290
Settlement payments......... -- -- -- -- (9) (444)
Benefit payments............ (546) (563) -- -- (791) (906)
Exchange adjustment......... (555) (1,607) -- -- -- --
------ ------ ------ ------ ------ ------
Fair value of plan assets
at December 31............ 16,880 19,617 -- -- 5,625 6,970
------ ------ ------ ------ ------ ------
Funded status............... 4,134 6,404 (1,510) (1,438) (521) 1,424
Unrecognized transition (asset)
obligation................ (154) (237) 51 69 (1) (5)
Unrecognized net actuarial (gain) loss (2,537) (5,021) 141 200 1,777 133
Unrecognized prior service cost 695 791 1 2 24 11
------ ------ ------ ------ ------ ------
Net amount recognized....... 2,138 1,937 (1,317) (1,167) 1,279 1,563
====== ====== ====== ====== ====== ======
Prepaid benefit cost (accrued
benefit liability)........ 2,138 1,937 (1,454) (1,391) (147) 1,513
Intangible asset............ -- -- 26 50 86 3
Accumulated other
comprehensive income...... -- -- 111 174 1,340 47
------ ------ ------ ------ ------ ------
2,138 1,937 (1,317) (1,167) 1,279 1,563
====== ====== ====== ====== ====== ======
F - 63
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 39 -- Other postretirement benefits
Certain Group companies in the USA provide postretirement healthcare and
life insurance benefits to their retired employees and dependants. The
entitlement to these benefits is usually based on the employee remaining in
service until retirement age and completion of a minimum period of service. The
plans are funded to a limited extent and the accrued net liability for
postretirement benefits is included within other provisions. The cost of
providing postretirement benefits is assessed annually by independent actuaries
using the projected unit credit method. The date of the latest actuarial
valuation was January 1, 2001.
The assumptions used in calculating the charge for postretirement benefits
are consistent with those shown in Note 38 for US pension plans.
The charge to income for postretirement benefits is as follows:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Service cost -- benefits earned during year.......... 31 25 34
Interest cost on projected benefit obligation........ 187 148 113
Expected return on plan assets....................... (5) (5) (4)
Recognized net actuarial gain........................ (6) (46) (31)
Amortization of prior service cost recognized........ (15) (20) (8)
Curtailment gains.................................... (32) (40) (62)
------ ------ ------
Postretirement benefit expense....................... 160 62 42
====== ====== ======
At December 31, 2001 the independent actuaries have reassessed the
obligation for postretirement benefits at $3,080 million ($2,562 million at
December 31, 2000). The provision for postretirement benefits at December 31,
2001 was $2,664 million ($2,726 million at December 31, 2000).
The discount rate used to assess the obligation at December 31, 2001 was
7.25% (7.5% at December 31, 2000). The assumed future healthcare cost trend rate
for beneficiaries aged under 65 (over 65) for 2002 is 12% (15%), for 2003 is 10%
(11%) and for 2004 is 8% (8%) and for 2005 and subsequent years is 5% (5%).
F - 64
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 39 -- Other postretirement benefits (continued)
As indicated in Note 38 -- Pensions, certain additional disclosures are
required by FRS 17 for the year ended December 31, 2001. The expected long-term
rates of return and market values of the assets of the postretirement benefits
plans at December 31, 2001 were as follows:
USA
------------------
Expected
long-term
rate of Market
return value
---------- -------
(%) ($ million)
Market value of assets at December 31, 2001
Equities............................................................. 11.0 30
Bonds................................................................ 7.0 11
-------
41
Present value of scheme liabilities.................................. 3,080
-------
Other postretirement benefit liability before deferred tax........... (3,039)
Deferred tax......................................................... 1,124
-------
(1,915)
=======
F - 65
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 39 -- Other postretirement benefits (concluded)
Further information presented in compliance with the requirements of FASB
Statement of Financial Accounting Standards No. 132 -- 'Employers' Disclosures
about Pensions and Other Postretirement Benefits' is set out below.
2001 2000
------ ------
($ million)
Benefit obligation at January 1........................... 2,562 1,638
Service cost.............................................. 31 25
Interest cost............................................. 187 148
Plan amendments........................................... 78 --
Curtailment gain.......................................... (30) (9)
Actuarial loss............................................ 476 340
Acquisitions.............................................. -- 579
Benefit payments.......................................... (224) (159)
------ ------
Benefit obligation at December 31......................... 3,080 2,562
------ ------
Fair value of plan assets at January 1.................... 49 53
Actual return on plan assets.............................. (4) --
Benefits payments......................................... (4) (4)
------ ------
Fair value of plan assets at December 31.................. 41 49
------ ------
Funded status............................................. (3,039) (2,513)
Unrecognized net actuarial (gain) loss.................... 349 (144)
Unrecognized prior service cost........................... 26 (69)
------ ------
Provision for postretirement benefits..................... (2,664) (2,726)
====== ======
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 One-percentage
point Increase point Decrease
-------------- --------------
($ million)
Effect on total of service and interest cost in 2001........ 32 (27)
Effect on postretirement obligation at December 31, 2001.... 339 (291)
F - 66
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 40 -- Contingent Liabilities
There were contingent liabilities at December 31, 2001 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 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, 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 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 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.
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.
The Group is subject to numerous 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 of 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.
F - 67
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 41 -- Joint ventures and associated undertakings
The significant joint ventures and associated undertakings of the BP Group
at December 31, 2001 are shown in Note 44. Transactions between these entities
and the Group are summarized below.
Sales to joint ventures and associated undertakings
2001 2000 1999
---------------------- --------------------- -------
Amount Amount
receivable at receivable at
Product Sales December 31 Sales December 31 Sales
------- ----- ------------- ----- ------------- -----
($ million) ($ million) ($million)
Joint ventures
Pan American Energy Crude oil 121 5 101 5 --
BP/Mobil Crude oil and products -- -- 2,933 -- 3,398
Watson Cogeneration Natural gas 177 3 87 34 --
Associated undertakings
Erdoelchemie Chemical feedstocks 250 -- 718 -- 460
Ruhrgas Natural gas 124 11 78 11 47
Purchases from joint ventures and asssociated undertakings
2001 2000 1999
---------------------- --------------------- -------
Amount Amount
payable at payable at
Product Purchases December 31 Purchases December 31 Purchases
------- --------- ------------- --------- ------------- ---------
($ million) ($ million) ($ million)
Joint ventures
Pan American Energy Crude oil 178 14 139 41 29
BP/Mobil Crude oil and products -- -- 1,762 -- 1,791
Watson Cogeneration Electricity and steam 187 7 129 26 --
Associated undertakings
Abu Dhabi Marine Areas Crude oil 555 37 671 62 407
Abu Dhabi Petroleum Crude oil 820 47 948 75 528
Erdoelchemie Petrochemicals 50 -- 114 -- 77
Ruhrgas Natural gas 18 -- -- -- --
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.
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.
F - 68
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 42 -- Oil and gas exploration and production activities (a)
Capitalized costs at December 31
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
2001
Gross capitalized costs:
Proved properties.................... 23,607 2,912 43,070 22,820 92,409
Unproved properties.................. 333 120 1,224 2,345 4,022
-------- -------- -------- -------- --------
23,940 3,032 44,294 25,165 96,431
Accumulated depreciation (b)........... 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 (b)........... 13,182 1,797 18,204 8,933 42,116
-------- -------- -------- -------- --------
Net capitalized costs.................. 11,619 959 22,044 14,123 48,745
======== ======== ======== ======== ========
1999
Gross capitalized costs:
Proved properties.................... 22,874 2,738 35,826 14,166 75,604
Unproved properties.................. 412 79 741 2,067 3,299
-------- -------- -------- -------- --------
23,286 2,817 36,567 16,233 78,903
Accumulated depreciation (b)........... 13,160 1,890 20,751 8,279 44,080
-------- -------- -------- -------- --------
Net capitalized costs.................. 10,126 927 15,816 7,954 34,823
======== ======== ======== ======== ========
F - 69
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 42 -- Oil and 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)
2001
Acquisition of properties:
Proved............................... -- -- -- 47 47
Unproved............................. 4 -- 20 193 217
-------- -------- -------- -------- --------
4 -- 20 240 264
Exploration and appraisal costs (c).... 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............................... 2,954 -- 9,152 2,647 14,753
Unproved............................. 161 -- 508 1,880 2,549
-------- -------- -------- -------- --------
3,115 -- 9,660 4,527 17,302
Exploration and appraisal costs (c).... 86 67 676 466 1,295
Development costs...................... 808 153 2,328 1,274 4,563
-------- -------- -------- -------- --------
Total costs............................ 4,009 220 12,664 6,267 23,160
======== ======== ======== ======== ========
1999
Acquisition of properties:
Proved............................... -- -- 396 -- 396
Unproved............................. -- -- 23 130 153
-------- -------- -------- -------- --------
-- -- 419 130 549
Exploration and appraisal costs (c).... 83 39 287 439 848
Development costs...................... 676 71 1,212 956 2,915
-------- -------- -------- -------- --------
Total costs............................ 759 110 1,918 1,525 4,312
======== ======== ======== ======== ========
F - 70
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 42 -- Oil and gas exploration and production activities (a) (continued)
Results of operations for the year ended December 31
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
2001
Turnover (d):
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 (e)........................ 25 33 1,743 1,534 3,335
Depreciation and amounts provided...... 1,353 115 3,034 1,115 5,617
-------- -------- -------- -------- --------
2,829 278 6,796 4,440 14,343
-------- -------- -------- -------- --------
Profit before taxation (f)............. 3,153 748 4,491 3,033 11,425
Allocable taxes........................ 1,046 379 933 1,016 3,374
-------- -------- -------- -------- --------
Results of operations ................. 2,107 369 3,558 2,017 8,051
======== ======== ======== ======== ========
2000
Turnover (d):
Third parties........................ 3,538 926 4,242 2,446 11,152
Sales between businesses............. 3,191 138 6,755 5,593 15,677
-------- -------- -------- -------- --------
6,729 1,064 10,997 8,039 26,829
-------- -------- -------- -------- --------
Exploration expense.................... 36 42 257 264 599
Production costs....................... 772 86 1,311 786 2,955
Production taxes....................... 641 6 437 911 1,995
Other costs (e)........................ 74 6 1,624 1,889 3,593
Depreciation and amounts provided...... 1,453 98 2,406 748 4,705
-------- -------- -------- -------- --------
2,976 238 6,035 4,598 13,847
-------- -------- -------- -------- --------
Profit before taxation (f)............. 3,753 826 4,962 3,441 12,982
Allocable taxes........................ 1,127 516 1,042 1,018 3,703
-------- -------- -------- -------- --------
Results of operations ................. 2,626 310 3,920 2,423 9,279
======== ======== ======== ======== ========
F - 71
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 42 -- Oil and gas exploration and production activities (a) (continued)
Results of operations for the year ended December 31 (continued)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
1999
Turnover (d):
Third parties........................ 2,258 644 4,738 2,216 9,856
Sales between businesses............. 2,251 108 1,283 2,938 6,580
-------- -------- -------- -------- --------
4,509 752 6,021 5,154 16,436
-------- -------- -------- -------- --------
Exploration expense.................... 51 20 172 305 548
Production costs....................... 734 98 1,387 756 2,975
Production taxes....................... 167 2 283 495 947
Other costs (e)........................ 157 16 1,231 1,143 2,547
Depreciation and amounts provided...... 1,306 138 1,113 651 3,208
-------- -------- -------- -------- --------
2,415 274 4,186 3,350 10,225
-------- -------- -------- -------- --------
Profit before taxation (f)............. 2,094 478 1,835 1,804 6,211
Allocable taxes........................ 643 312 483 497 1,935
-------- -------- -------- -------- --------
Results of operations ................. 1,451 166 1,352 1,307 4,276
======== ======== ======== ======== ========
----------
The Group's share of joint ventures' and associated undertakings' results
of operations in 2001 was a profit of $246 million (2000 $293 million and
1999 $204 million) after deducting a tax charge of $138 million (2000 $97
million tax charge and 1999 $6 million tax credit).
The Group's share of joint ventures' and associated undertakings' net
capitalized costs at December 31, 2001 was $3,078 million (December 31,
2000 $3,354 million and December 31, 1999 $1,442 million).
The Group's share of joint ventures' and associated undertakings' costs
incurred in 2001 was $419 million (2000 $1,490 million and 1999 $49
million).
(a) This note relates to the requirements contained within the UK Statement of
Recommended Practice 'Accounting for Oil and Gas Exploration, Development,
Production and Decommissioning Activities'. Midstream activities of natural
gas gathering and distribution and the operation of the main pipelines and
tankers are excluded. The main midstream activities are the Alaskan
transportation facilities, the Forties Pipeline system and the Central Area
Transmission System. The Group's share of joint ventures' and associated
undertakings' activities is excluded from the tables and included in the
footnotes with the exception of the Abu Dhabi operations which are included
in the income and expenditure items above. Profits (losses) on sale of
businesses and fixed assets relating to the oil and natural gas exploration
and production activities, which have been accounted as exceptional items,
are also excluded.
(b) Accumulated depreciation consists of depreciation, depletion and
amortization related to oil and natural gas producing activities.
(c) Exploration and appraisal drilling expenditure and licence acquisition
costs are initially capitalized within intangible fixed assets in
accordance with the Group's accounting policy.
(d) Turnover represents sales of production excluding royalty oil where royalty
is payable in kind.
F - 72
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 42 -- Oil and gas exploration and production activities (a) (concluded)
(e) Includes cost of royalty oil not taken in kind, property taxes and other
government take.
(f) The exploration and production total replacement cost operating profit
comprises:
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
($ million)
Year ended December 31, 2001
Exploration and production activities......
-- Group (as above)........................ 3,153 748 4,491 3,033 11,425
-- Equity-accounted entities............... -- -- -- 384 384
Midstream activities....................... 271 -- 138 199 608
-------- -------- -------- -------- --------
Total replacement cost operating profit 3,424 748 4,629 3,616 12,417
======== ======== ======== ======== ========
Year ended December 31, 2000
Exploration and production activities
-- Group (as above)........................ 3,753 826 4,962 3,441 12,982
-- Equity-accounted entities............... -- -- -- 390 390
Midstream activities....................... 290 -- 152 198 640
-------- -------- -------- -------- --------
Total replacement cost operating profit 4,043 826 5,114 4,029 14,012
======== ======== ======== ======== ========
Year ended December 31, 1999
Exploration and production activities
-- Group (as above)....................... 2,094 478 1,835 1,804 6,211
-- Equity-accounted entities.............. -- -- 45 153 198
Midstream activities...................... 216 9 256 93 574
-------- -------- -------- -------- --------
Total replacement cost operating profit 2,310 487 2,136 2,050 6,983
======== ======== ======== ======== ========
Note 43 -- US generally accepted accounting principles
The consolidated financial statements of the BP Group are prepared in
accordance with UK GAAP which differs in certain respects from US GAAP. The
principal differences between US GAAP and UK GAAP for BP Group reporting relate
to the following:
(a) Group consolidation
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 (for example 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 - 73
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- 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, 2001
---------------------------------------
As US GAAP
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............................................. 5,017 (297) 4,720
Profit for the year.................................. 8,010 -- 8,010
Year ended December 31, 2000
---------------------------------------
As US GAAP
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............................................. 4,972 (219) 4,753
Profit for the year.................................. 11,870 -- 11,870
Year ended December 31, 1999
---------------------------------------
As US GAAP
reported Reclassification presentation
-------- ---------------- ------------
($ million)
Consolidated statement of income
Other income......................................... 414 1,399 1,813
Share of profits of JVs and associated undertakings.. 1,158 (1,158) --
Exceptional items before taxation.................... (2,280) 1 (2,279)
Inventory holding gains (losses)..................... 1,728 (547) 1,181
Interest expense..................................... 1,316 (201) 1,115
Taxation............................................. 1,880 (104) 1,776
Profit for the year.................................. 5,008 -- 5,008
(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.
F - 74
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
(d) Deferred taxation/Business combinations
Under the UK GAAP restricted liability method, deferred taxation is only
provided where timing differences are expected to reverse in the
foreseeable future. Under US GAAP deferred taxation is provided for
temporary differences between the financial reporting basis and the tax
basis of the Group's assets and liabilities at enacted tax rates.
US GAAP requires the recognition of a deferred tax asset or liability for
the tax effects of differences between the assigned values and the tax
bases of assets acquired and liabilities assumed in a purchase business
combination, whereas under UK GAAP no such deferred tax asset or liability
is recognized. Under US GAAP the deferred tax asset or liability is
amortized over the same period as the assets and liabilities to which it
relates.
The adjustments 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,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Replacement cost of sales........................... 1,091 706 115
Increase in tax charge from restricted liability
to gross potential ............................... 2,124 1,554 442
Taxation resulting from business combinations....... (1,074) (672) (91)
Profit for the year................................. (2,141) (1,588) (466)
====== ====== =======
At December 31,
---------------
2001 2000
------ ------
($ million)
Tangible assets................................................... 7,032 8,367
Increase in provision from restricted liability
to gross potential liability.................................... 10,047 8,014
Tax liability resulting from business combinations................ 7,014 8,336
BP shareholders' interest......................................... (10,029) (7,983)
====== ======
The major components of deferred tax liabilities and assets on a US GAAP
basis were as follows:
At December 31,
---------------
2001 2000
------ ------
($ million)
Depreciation.......................................... (19,709) (20,399)
Other taxable temporary differences................... (1,110) (1,328)
------ ------
Total deferred tax liabilities........................ (20,819) (21,727)
------ ------
Petroleum revenue tax................................. 383 337
Decommissioning and other provisions.................. 2,446 2,610
Tax credit and loss carry forward..................... 1,487 1,113
Other deductible temporary differences................ 668 357
------ ------
Gross deferred tax assets............................. 4,984 4,417
Valuation allowance................................... (1,474) (219)
------ ------
Net deferred tax assets............................... 3,510 4,198
------ ------
Net deferred tax liability*........................... (17,309) (17,529)
====== ======
----------
* Primarily noncurrent.
F- 75
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
(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 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,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Replacement cost of sales............................. 523 340 121
Interest expense...................................... (238) (189) (110)
Taxation.............................................. (103) (83) (20)
Profit for the year................................... (182) (68) 9
====== ====== =======
At December 31,
---------------
2001 2000
------ ------
($ million)
Tangible assets....................................... (785) (402)
Provisions............................................ 780 921
Deferred taxation..................................... (511) (410)
BP shareholders' interest............................. (1,054) (913)
====== =======
(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 $911 million to the previously reported fair values
for tangible fixed assets relating to the 2000 acquisition of ARCO under UK
GAAP has been reflected as a charge for impairment under US GAAP.
F - 76
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
(f) Impairment (concluded)
The adjustments to profit for the year to accord with US GAAP are shown
below. There is no impact on BP shareholders' interest. The consequential
balance sheet adjustments are reflected in (d) Deferred taxation/Business
combinations and (h) Goodwill.
Increase (decrease) in caption heading Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Replacement cost of sales............................. 1,150 -- --
Taxation.............................................. (239) -- --
Profit for the year................................... (911) -- --
====== ====== =======
(g) Sale and leaseback
The sale and leaseback of the Amoco building in Chicago, Illinois in 1998
is treated as a sale for UK GAAP whereas for US GAAP it is treated as a
financing transaction.
A provision was recognized under UK GAAP in 1999 to cover the likely
shortfall on rental income from subletting the Chicago office building. As
the original sale and leaseback was not treated as a sale for US GAAP the
provision has been reversed for US GAAP.
Under UK GAAP the profit arising on the sale and operating leaseback of
certain railcars in 1999 is taken to income in the period in which the
transaction occurs. Under US GAAP this profit is not recognized immediately
but amortized over the term of the operating lease.
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,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Replacement cost of sales............................. 51 49 (123)
Exceptional items..................................... -- -- (37)
Taxation.............................................. (15) (15) 24
Profit for the year................................... (36) (34) 62
====== ====== =======
At December 31,
---------------
2001 2000
------ ------
($ million)
Tangible assets....................................... 171 181
Other accounts payable and accrued liabilities........ 30 34
Provisions............................................ (65) (105)
Finance debt.......................................... 413 413
Deferred taxation..................................... (73) (57)
BP shareholders' interest............................. (134) (104)
====== =======
F - 77
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
(h) Goodwill
In 2001, under UK GAAP, revisions to the previously reported fair values of
tangible fixed assets and the liability for taxation relating to the ARCO
acquisition have resulted in a net increase of goodwill of $97 million.
Under US GAAP, the revision to tangible fixed assets of $911 million is
accounted as a charge for impairment. This results in a GAAP difference of
$911 million in goodwill.
This adjustment plus other differences in the basis for determining
goodwill between UK and US GAAP, result in goodwill for US GAAP being lower
than for UK GAAP at the year end. The amortization of the difference is
included within replacement cost of sales.
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Replacement cost of sales............................. 68 48 --
Taxation.............................................. -- -- --
Profit for the year................................... (68) (48) --
====== ====== =======
At December 31,
---------------
2001 2000
------ ------
($ million)
Intangible assets..................................... (348) 631
Deferred taxation..................................... -- --
BP shareholders' interest............................. (348) 631
====== =======
(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.
The Group's accounting policies under UK GAAP do not satisfy the criteria
for hedge accounting under SFAS 133. The Group does not intend to modify
its practice under UK GAAP.
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 - 78
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- 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 those derivative instruments,
there was no impact of adopting SFAS 133 on the Group's results of
operations and financial position, as adjusted to accord with 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) and a pre-tax
credit to other comprehensive income of $57 million ($37 million after
tax). The net gain included in other comprehensive income as of January 1,
2001 has been reclassified into earnings during 2001. 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.
SFAS 133 requires these contracts to be marked to market. On the basis of
SFAS 133 Implementation Issue C11, the cumulative effect of adopting SFAS
133 for these derivatives resulted in a pre-tax charge to income, as
adjusted to accord with US GAAP, at July 1, 2001 of $530 million ($344
million after tax).
Because the Company does not intend to modify its accounting practice to
satisfy the criteria for hedge accounting under SFAS 133, the Group's
results of operations, as adjusted to accord with US GAAP, will not
necessarily be representative of the results it would report if US GAAP
were used to prepare the consolidated financial statements of the Group and
the Group sought to meet the hedge criteria of SFAS 133.
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Replacement cost of sales............................. 481 -- --
Taxation.............................................. (168) -- --
Profit for the year before cumulative
effect of accounting change......................... (313) -- --
Cumulative effect of accounting change,
net of taxation..................................... (362) -- --
Profit for the year................................... (675) -- --
====== ====== =======
At December 31,
---------------
2001 2000
------ ------
($ million)
Accounts payable and accrued liabilities..................... 1,038 --
Deferred taxation............................................ (363) --
BP shareholders' interest.................................... (675) --
====== ======
F - 79
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
(j) Gain arising on asset exchange
For UK GAAP the transaction with Solvay, 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 ($157 million after tax).
The adjustments to profit for the year and to BP shareholders' interest to
accord with US GAAP are summarized below.
Increase (decrease) in caption heading Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Profit (loss) on sale of fixed assets
and businesses or termination of operations............ 242 -- --
Taxation................................................. 85 -- --
Profit for the year...................................... 157 -- --
====== ====== =======
At December 31,
---------------
2001 2000
------ ------
($ million)
Intangible assets........................................... 188 --
Accounts payable and accrued liabilities.................... (54) --
Deferred taxation........................................... 85 --
BP shareholders' interest................................... 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 2001 2000
------ ------
($ million)
Fixed assets -- Investments................................. (266) (360)
BP shareholders' interest................................... (266) (360)
====== =======
F - 80
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- 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 2001 2000
------ ------
($ million)
Other accounts payable and accrued liabilities............... (1,288) (1,178)
BP shareholders' interest.................................... 1,288 1,178
======= =======
(m) Debt retirement charges
Under US GAAP charges arising on the early retirement of debt would be
shown as an extraordinary item. Under UK GAAP they are included within
interest expense.
(n) Investments
Under UK GAAP the Group's equity investments in Lukoil, Sinopec and
PetroChina are held for the long term and reported as fixed 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 2001 2000
------ ------
($ million)
Fixed assets -- Investments.................................. (3) (172)
Deferred taxation............................................ (1) (60)
BP shareholders' interest.................................... (2) (112)
====== =======
F - 81
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
(o) 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 2001 2000
------ ------
($ million)
Intangible assets............................................. 112 53
Other receivables falling due after
more than one year.......................................... (1,015) --
Noncurrent liabilities -- accounts payable and
accrued liabilities......................................... 548 274
Deferred taxation............................................. (509) (76)
BP shareholders' interest..................................... (942) (145)
====== =======
(p) Balance sheet
Under US GAAP Trade and Other receivables due after one year of $4,681
million at December 31, 2001 ($4,610 million at December 31, 2000),
included within current assets, would have been classified as noncurrent
assets. Borrowing under US Industrial Revenue/Municipal Bonds of $1,768
million (December 31, 2000 $1,671 million) included within Current
liabilities - falling due within one year would, under US GAAP, have been
classified as noncurrent liabilities. The provision for deferred taxation
is primarily in respect of noncurrent items.
F - 82
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
The following is a summary of the adjustments to profit for the year and to
BP shareholders' interest which would be required if generally accepted
accounting principles in the USA (US GAAP) had been applied instead of those
generally accepted in the United Kingdom (UK GAAP).
These results are stated using the first-in first-out method of stock
valuation.
Profit for the year Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million except
per share amounts)
Profit as reported in the consolidated statement of income..... 8,010 11,870 5,008
Adjustments:
Deferred taxation/business combinations (d).................. (2,141) (1,588) (466)
Provisions (e)............................................... (182) (68) 9
Impairment (f)............................................... (911) -- --
Sale and leaseback (g)....................................... (36) (34) 62
Goodwill (h)................................................. (68) (48) --
Derivative financial instruments (i)......................... (313) -- --
Gain arising on asset exchange (j)........................... 157 -- --
Other........................................................ 10 51 (17)
------ ------ ------
Profit for the year before cumulative effect of accounting
change as adjusted to accord with US GAAP..................... 4,526 10,183 4,596
Cumulative effect of accounting change:
Derivative financial instruments (i).......................... (362) -- --
------ ------ ------
Profit for the year as adjusted to accord with US GAAP. 4,164 10,183 4,596
Dividend requirements on preference shares..................... 2 2 2
------ ------ ------
Profit for the year applicable to ordinary shares as
adjusted to accord with US GAAP............................... 4,162 10,181 4,594
====== ====== ======
Profit for the year as adjusted:
Per ordinary share -- cents
Basic -- before cumulative effect of accounting change........ 20.16 47.05 23.70
Cumulative effect of accounting change........................ (1.61) -- --
------ ------ ------
18.55 47.05 23.70
------ ------ ------
Diluted -- before cumulative effect of accounting change...... 20.04 46.74 23.56
Cumulative effect of accounting change........................ (1.60) -- --
------ ------ ------
18.44 46.74 23.56
------ ------ ------
Per American Depositary Share -- cents
Basic -- before cumulative effect of accounting change........ 120.96 282.30 142.20
Cumulative effect of accounting change........................ (9.66) -- --
------ ------ ------
111.30 282.30 142.20
------ ------ ------
Diluted -- before cumulative effect of accounting change...... 120.24 280.44 141.36
Cumulative effect of accounting change........................ (9.60) -- --
------ ------ ------
110.64 280.44 141.36
------ ------ ------
F - 83
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
BP shareholders' interest
At December 31,
---------------
2001 2000
------ ------
($ million)
BP shareholders' interest as reported in the
consolidated balance sheet...................................... 74,367 73,416
Adjustments:
Deferred taxation/business combinations (d)..................... (10,029) (7,983)
Provisions (e).................................................. (1,054) (913)
Sale and leaseback (g).......................................... (134) (104)
Goodwill (h).................................................... (348) 631
Derivative financial instruments (i)............................ (675) --
Gain arising on asset exchange (j).............................. 157 --
Ordinary shares held for future awards to employees (k)......... (266) (360)
Dividends (l)................................................... 1,288 1,178
Investments (n)................................................. (2) (112)
Additional minimum pension liability (o)........................ (942) (145)
Other........................................................... (40) (54)
------ ------
BP shareholders' interest as adjusted to accord with US GAAP...... 62,322 65,554
====== ======
Comprehensive income
The components of comprehensive income, net of related tax are as follows:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Profit for the period as adjusted to
accord with US GAAP.......................................... 4,164 10,183 4,596
Currency translation differences............................... (908) (2,508) (921)
Net unrealized gain (loss) on investments...................... 110 (112) --
Additional minimum pension liability........................... (797) (1) (1)
------ ------ ------
Comprehensive income........................................... 2,569 7,562 3,674
====== ====== ======
Accumulated other comprehensive income at December 31, 2001 comprised
currency translation losses of $4,790 million ($3,882 million at December 31,
2000), pension liability adjustments of $942 million ($145 million at December
31, 2000) and net unrealized losses on investments of $2 million ($112 million
at December 31, 2000).
F - 84
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- 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 (FRS
1). The statement prepared under FRS 1 presents substantially the same
information as that required under FASB Statement of Financial Accounting
Standards No. 95 'Statement of Cash Flows' (SFAS 95).
Under FRS 1 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 FRS 1 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
FRS 1 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 FRS 1. 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 - 85
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
The statement of consolidated cash flows presented in accordance with SFAS
95 is as follows:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Operating activities
Profit after taxation......................................... 8,083 11,962 5,146
Adjustments to reconcile profit after tax to
net cash provided by operating activities:
Depreciation and amounts provided........................... 8,750 7,449 4,965
Exploration expenditure written off......................... 238 264 304
Share of profits of joint ventures and associated
undertakings less dividends received...................... (60) (377) (232)
(Profit) loss on sale of businesses and fixed assets (537) (196) 379
Working capital movement (a)................................ 1,319 (2,848) (1,877)
Other....................................................... (225) (1,650) 215
------ ------ ------
Net cash provided by operating activities..................... 17,568 14,604 8,900
------ ------ ------
Investing activities
Capital expenditures.......................................... (12,295) (10,220) (6,314)
Acquisitions net of cash acquired............................. (1,210) (6,265) (102)
Investment in associated undertakings......................... (586) (985) (197)
Net investment in joint ventures.............................. (497) (218) (750)
Proceeds from disposal of assets.............................. 2,903 11,362 2,441
------ ------ ------
Net cash used in investing activities......................... (11,685) (6,326) (4,922)
------ ------ ------
Financing activities
Proceeds from shares (repurchased) issued..................... (1,100) (2,039) 245
Proceeds from long-term financing............................. 1,296 1,680 2,140
Repayments of long-term financing............................. (2,602) (2,353) (2,268)
Net increase (decrease) in short-term debt.................... 1,434 (701) 837
Dividends paid -- Shareholders................................ (4,827) (4,415) (4,135)
-- Minority shareholders....................... (54) (24) (151)
------ ------ ------
Net cash used in financing activities......................... (5,853) (7,852) (3,332)
------ ------ ------
Currency translation differences relating to cash
and cash equivalents........................................ (53) (50) 15
------ ------ ------
Increase (decrease) in cash and cash equivalents.............. (23) 376 661
Cash and cash equivalents at beginning of year................ 1,831 1,455 794
------ ------ ------
Cash and cash equivalents at end of year...................... 1,808 1,831 1,455
====== ====== ======
----------
(a) Working capital:
Inventories decrease (increase).................... 1,490 (1,449) (1,562)
Receivables decrease (increase).................... 1,905 (5,501) (3,854)
Current liabilities -- excluding
finance debt (decrease) increase................. (2,076) 4,102 3,539
------ ------ ------
1,319 (2,848) (1,877)
====== ====== ======
F - 86
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (continued)
Impact of new US accounting standards
Business combinations, goodwill and other intangible assets: In June 2001
the Financial Accounting Standards Board (FASB) issued Statement of Financial
Accounting Standards No.141 'Business Combinations' (SFAS 141) and No. 142
'Goodwill and Other Intangible Assets' (SFAS 142). Under SFAS 141, the pooling
of interest method of accounting is no longer permitted; the purchase method
must be used for all business combinations initiated after June 30, 2001. SFAS
142, which is effective for accounting periods beginning after December 15,
2001, 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 will
continue to be amortized over their estimated useful lives.
It is estimated that elimination of the requirement to amortize goodwill
would increase the Group's results of operations, as adjusted to accord with US
GAAP, by approximately $1,200 million for the year ended December 31, 2002,
assuming no impairment of goodwill.
Asset retirement obligations: Also in June 2001 the 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 provisions of SFAS 143 are similar to the accounting policy used by the
Group in preparing its financial statements under UK GAAP. The Company has not
yet determined the effect of adopting SFAS 143 on its results of operations or
shareholders' interest as adjusted to accord with US GAAP.
Impairment or disposal of long-lived assets: In August 2001, the FASB
issued 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. SFAS 144 is effective for
accounting periods beginning after December 15, 2001.
The Company has not yet determined the effect of adopting SFAS 144 on its
results of operations and shareholders' interest as adjusted to accord with US
GAAP.
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 is fully effective for accounting periods ending on or after June 22,
2003. Certain of the disclosure requirements are effective for periods prior to
2003. 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
Company has not yet completed its evaluation of the impact of adopting FRS 17 on
the Group's results of operations, and there will be no significant effect on
the Group's financial position.
F - 87
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 43 -- US generally accepted accounting principles (concluded)
Impact of new UK accounting standards (concluded)
Deferred taxation: In December 2000, the UK Accounting Standards Board
issued Financial Reporting Standard No.19 'Deferred Tax' (FRS 19). The standard
requires that deferred tax should be provided in full on most timing
differences. FRS 19 permits, but does not require, discounting of deferred tax
assets and liabilities. The Group has adopted FRS 19 with effect from January 1,
2002. If this new standard had been applied to the reported results for 2001,
the tax charge for the year under UK GAAP would have increased by $1,358 million
to $6,375 million. In addition, at December 31, 2001 there would have been a
reduction of $9,050 million in shareholders' funds and capital employed.
F - 88
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 44 -- Business and geographical analysis
BP has four reportable operating segments -- Exploration and Production,
Gas and Power, Refining and Marketing and Chemicals. Exploration and
Production's activities include oil and natural gas exploration and field
development and production (upstream activities), together with pipeline
transportation and natural gas processing (midstream activities). Gas and Power
activities include marketing and trading of natural gas, liquefied natural gas,
natural gas liquids and power, the development of international opportunties
that monetize upstream gas resources and involvement in select power projects.
The activities of Refining and Marketing include oil supply and trading as well
as refining and marketing (downstream activities). Chemicals activities include
petrochemicals manufacturing and marketing.
The Group is managed on a unified basis. Reportable segments are
differentiated by the activities that each undertakes and the products they
manufacture and market.
The accounting policies of operating segments are the same as those
described in Note 1, Accounting Policies. Performance is evaluated based on
replacement cost operating profit or loss, which excludes exceptional items,
inventory holding gains and losses, interest income and expense, taxation and
minority shareholders' interests.
Sales between segments are made at prices that approximate market prices
taking into account the volumes involved.
F - 89
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 44 -- Business and geographical analysis (continued)
By business
Other
Exploration Gas Refining businesses
and and and and
Production Power Marketing Chemicals corporate(a) Eliminations Total
----------- ----- --------- --------- --------- ------------ -----
($ million)
2001
Group turnover -- third parties........ 8,569 36,254 117,330 11,282 783 -- 174,218
-- sales between
businesses (b)....... 19,660 2,954 2,903 233 -- (25,750) --
------ ------ ------- ------ ------- ------- ------
28,229 39,208 120,233 11,515 783 (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).................... 12,417 521 3,625 128 (556) 16,135
Exceptional items (e).................. 195 (1) 471 (297) 167 535
Inventory holding gains (losses) (6) (81) (1,583) (230) -- (1,900)
------ ------ ------- ------ ------- ------
Historical cost profit (loss) before
interest and tax..................... 12,606 439 2,513 (399) (389) 14,770
------ ------ ------- ------ ------- ------
Total assets (f)....................... 69,572 5,313 43,102 15,098 8,073 141,158
Operating capital employed (g)......... 59,701 2,764 24,868 11,996 1,850 101,179
Depreciation and amounts provided (h).. 5,987 54 2,250 588 109 8,988
Capital expenditure and acquisitions (i) 8,861 359 2,415 1,926 563 14,124
2000
Group turnover -- third parties........ 14,155 20,667 101,960 11,031 249 -- 148,062
-- sales between
businesses (b)....... 16,787 346 5,923 216 -- (23,272) --
------ ------ ------- ------ ------- ------- -------
30,942 21,013 107,883 11,247 249 (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).................... 14,012 571 3,523 760 (1,110) 17,756
Exceptional items (e).................. 119 1 98 (212) 214 220
Inventory holding gains (losses)....... 4 11 620 93 -- 728
------ ------ ------- ------ ------- -------
Historical cost profit (loss) before
interest and tax..................... 14,135 583 4,241 641 (896) 18,704
------ ------ ------- ------ ------- -------
Total assets (f)....................... 65,904 6,605 45,785 13,674 11,970 143,938
Operating capital employed (g)......... 56,500 2,997 27,804 11,008 2,385 100,694
Depreciation and amounts provided (h).. 5,156 47 1,715 704 91 7,713
Capital expenditure and acquisitions (i) 6,383 336 8,693 1,585 30,616 47,613
F - 90
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 44 -- Business and geographical analysis (continued)
By business
Other
Exploration Gas Refining businesses
and and and and
Production Power Marketing Chemicals corporate(a) Eliminations Total
----------- ----- --------- --------- --------- ------------ -----
($ million)
1999
Group turnover -- third parties......... 9,070 7,629 57,619 9,050 198 -- 83,566
-- sales between
businesses (b)........ 10,063 444 2,524 342 -- (13,373) --
------ ------ ------- ------ ------- ------- -------
19,133 8,073 60,143 9,392 198 (13,373) 83,566
------ ------ ------- ------ ------- -------
Share of sales by joint ventures........ 17,614
---------
101,180
---------
Equity accounted income (c)............. 297 179 503 125 54 1,158
------ ------ ------- ------ ------- -------
Total replacement cost operating
profit (loss) (d)..................... 6,983 211 1,840 686 (826) 8,894
Exceptional items (e)................... (1,111) 14 (334) (257) (592) (2,280)
Inventory holding gains (losses)........ (1) -- 1,613 116 -- 1,728
------ ------ ------- ------ ------- -------
Historical cost profit (loss) before
interest and tax...................... 5,871 225 3,119 545 (1,418) 8,342
------ ------ ------- ------ ------- -------
Total assets (f)........................ 44,967 2,831 26,099 13,021 2,643 89,561
Operating capital employed (g).......... 36,229 2,242 13,209 10,048 1,192 62,920
Depreciation and amounts provided (h)... 3,704 46 765 632 206 5,353
Capital expenditure and acquisitions (i) 4,194 81 1,571 1,215 284 7,345
By geographical area
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 7,049 4,604 16,135
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 6,324 4,919 14,770
------- ------- ------- ------- -------
Total assets (f)........................ 29,951 15,287 62,254 33,666 141,158
Operating capital employed (g).......... 19,477 7,346 44,292 30,064 101,179
Depreciation and amounts provided (h)... 2,159 513 4,829 1,487 8,988
Capital expenditure and acquisitions (i) 2,128 1,787 6,160 4,049 14,124
F - 91
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 44 -- Business and geographical analysis (continued)
Rest of Rest of
UK(j) Europe USA World Eliminations Total
---------- --------- --------- ---------- ------------ -----
($ million)
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 7,296 4,674 17,756
Exceptional items (e).................. 12 (19) 459 (232) 220
Inventory holding gains (losses)....... 103 107 387 131 728
------- ------- ------- ------- -------
Historical cost profit before
interest and tax..................... 3,888 2,101 8,142 4,573 18,704
------- ------- ------- ------- -------
Total assets (f)....................... 35,713 14,584 62,141 31,500 143,938
Operating capital employed (g)......... 20,093 7,087 44,657 28,857 100,694
Depreciation and amounts provided (h).. 1,945 373 4,088 1,307 7,713
Capital expenditure and acquisitions (i) 7,438 2,041 34,037 4,097 47,613
1999
Group turnover -- third parties (k)..... 25,817 5,332 37,405 15,012 83,566
-- sales between areas 4,406 641 1,381 4,453 (10,881) --
------- ------- ------- ------- ------- -------
30,223 5,973 38,786 19,465 (10,881) 83,566
------- ------- ------- ------- -------
Share of sales by joint ventures 3,988 16,114 155 342 (2,985) 17,614
-------
101,180
-------
Equity accounted income (c)............. 48 619 198 293 1,158
------- ------- ------- ------- -------
Total replacement cost operating
profit (d) ........................... 2,111 1,167 3,001 2,615 8,894
Exceptional items (e)................... (237) (258) (983) (802) (2,280)
Inventory holding gains (losses)........ 151 494 839 244 1,728
------- ------- ------- ------- -------
Historical cost profit before
interest and tax...................... 2,025 1,403 2,857 2,057 8,342
------- ------- ------- ------- -------
Total assets (f)........................ 22,867 8,865 38,223 19,606 89,561
Operating capital employed (g).......... 14,298 4,884 27,426 16,312 62,920
Depreciation and amounts provided (h)... 1,582 261 2,358 1,152 5,353
Capital expenditure and acquisitions (i) 1,518 831 2,963 2,033 7,345
----------
(a) Other businesses and corporate comprises Finance, BP Solar, the Group's
coal asset and aluminium asset, its investment in PetroChina and Sinopec,
interest income and costs relating to corporate activities worldwide.
(b) Sales and transfers between businesses are made at market prices taking
into account the volumes involved.
(c) Equity accounted income (loss) represents the Group's share of income
(loss) before interest expense and taxes of joint ventures and associated
undertakings.
(d) Total replacement cost operating profit (loss) is before inventory holding
gains and losses and interest expense, which is attributable to the
corporate function.
F - 92
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 44 -- Business and geographical analysis (concluded)
(e) Exceptional items comprise profit on sale of fixed assets and sale of
businesses or termination of operations of $535 million in 2001 (2000 $220
million profit and 1999 $337 million loss) and restructuring costs in 1999
of $1,943 million.
(f) Total assets comprise fixed and current assets and include investments in
joint ventures and associated undertakings analyzed between activities as
follows:
Other
Exploration Gas Refining businesses
and and and and
Production Power Marketing Chemicals corporate(a) Total
---------- ----- --------- --------- ---------- -----
($ million)
2001.......................... 5,326 857 1,675 1,416 154 9,428
----- ----- ----- ----- ----- -----
2000.......................... 5,093 744 1,220 1,155 127 8,339
----- ----- ----- ----- ----- -----
1999.......................... 2,550 762 4,771 1,350 105 9,538
----- ----- ----- ----- ----- -----
(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 and
$624 million in 1999 for the BP/Mobil joint venture.
(j) United Kingdom area includes the UK-based international activities of
Refining and Marketing.
(k) Turnover to third parties is stated by origin which is not materially
different from turnover by destination.
Note 45 -- Summarized financial information on joint ventures and associated
undertakings
A summarized statement of income and assets and liabilities based on latest
information available, with respect to the Group's equity accounted joint
ventures and associated undertakings, is set out below:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Sales and other operating revenue.................... 27,503 45,335 41,180
Gross profit......................................... 5,164 8,968 7,715
Profit for the year.................................. 3,105 4,219 2,641
====== ====== ======
At December 31,
-----------------
2001 2000
------ ------
($ million)
Fixed and other assets............................... 25,175 24,893
Current assets....................................... 14,402 12,606
------ ------
39,577 37,499
Current liabilities.................................. (10,022) (9,271)
Noncurrent liabilities............................... (9,365) (10,628)
------ ------
Net assets........................................... 20,190 17,600
====== ======
F - 93
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 45 -- Summarized financial information on joint ventures and associated
undertakings (concluded)
The more important joint ventures and associated undertakings of the Group
at December 31, 2001 and the percentage of equity capital owned or joint venture
interest are:
% Country of operation Principal activities
-- -------------------- --------------------
Associated undertakings
Abu Dhabi Marine Areas............................. 37 Abu Dhabi Crude oil production
Abu Dhabi Petroleum................................ 24 Abu Dhabi Crude oil production
BP Solvay Polyethylene North America............... 49 USA Chemicals
China American Petroleum Co........................ 50 Taiwan Chemicals
Ruhrgas............................................ 25 Germany Gas distribution
Rusia Petroleum.................................... 25 Russia Exploration and production
Sidanco (a)........................................ 11 Russia Integrated oil operations
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
----------
(a) 25% voting interest.
Note 46 -- Transfer of natural gas liquids business
With effect from January 1, 2001, the NGL business in North America was
transferred from Refining and Marketing to Gas and Power. Comparative
information for 2000 and 1999 has been restated to reflect this change.
December 31, 2000 As restated As reported
--------------------- ---------------------
Gas and Refining and Gas and Refining and
Power Marketing Power Marketing
------- ------------ ------- ------------
($ million except for number of employees)
Turnover....................................... 21,013 107,883 16,081 112,815
-------- -------- -------- --------
Group replacement cost operating profit........ 409 2,924 24 3,309
Joint ventures................................. -- 433 -- 433
Associated undertakings........................ 162 166 162 166
-------- -------- -------- --------
Total replacement cost operating profit........ 571 3,523 186 3,908
Exceptional items.............................. 1 98 -- 99
-------- -------- -------- --------
Replacement cost profit before interest and tax 572 3,621 186 4,007
-------- -------- -------- --------
Inventory holding gains (losses)............... 11 620 11 620
-------- -------- -------- --------
Capital expenditure and acquisitions........... 336 8,693 279 8,750
-------- -------- -------- --------
Operating capital employed..................... 2,997 27,804 1,735 29,066
-------- -------- -------- --------
Tangible assets................................ 1,322 17,619 472 18,469
-------- -------- -------- --------
Number of employees -- year end................ 1,600 67,100 1,000 67,700
-------- -------- -------- --------
Number of employees -- average................. 1,500 59,800 900 60,400
======== ======== ======== ========
F - 94
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 46 -- Transfer of natural gas liquids business (concluded)
December 31, 1999 As restated As reported
--------------------- ---------------------
Gas and Refining and Gas and Refining and
Power Marketing Power Marketing
------- ------------ ------- ------------
($ million except for number of employees)
Turnover....................................... 8,074 60,142 5,323 62,893
-------- -------- -------- --------
Group replacement cost operating profit........ 258 1,111 32 1,337
Joint ventures................................. -- 380 -- 380
Associated undertakings........................ 179 123 179 123
-------- -------- -------- --------
Total replacement cost operating profit........ 437 1,614 211 1,840
Exceptional items.............................. (1) (319) 14 (334)
-------- -------- -------- --------
Replacement cost profit before interest and tax 436 1,295 225 1,506
-------- -------- -------- --------
Inventory holding gains (losses)............... -- 1,613 -- 1,613
-------- -------- -------- --------
Number of employees -- year end................ 1,400 44,650 800 45,250
-------- -------- -------- --------
Number of employees -- average................. 1,400 47,900 800 48,500
======== ======== ======== ========
Note 47 -- Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees certain publicly issued debt
of its 100% owned subsidiary BP America Inc. BP p.l.c. also fully and
unconditionally guarantees the payment obligations of its 100% owned subsidiary
BP Exploration (Alaska) Inc. under the BP Prudhoe Bay Royalty Trust. The
following financial information for BP p.l.c., BP America Inc. and BP
Exploration (Alaska) Inc. and all other subsidiaries on a condensed
consolidating basis is intended to provide investors with meaningful and
comparable financial information about BP 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 America Inc., BP
Exploration (Alaska) Inc. and other subsidiaries.
F - 95
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Income statement
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 2001
Turnover .................................. 1,243 1,919 -- 174,146 (1,919) 175,389
Less: Joint ventures....................... -- -- -- 1,171 -- 1,171
------- ------- ------- ------- ------- -------
Group turnover............................. 1,243 1,919 -- 172,975 (1,919) 174,218
Replacement cost of sales.................. 1,351 971 -- 146,753 (2,182) 146,893
Production taxes........................... -- 192 -- 1,497 -- 1,689
------- ------- ------- ------- ------- -------
Gross profit............................... (108) 756 -- 24,725 263 25,636
Distribution and administration expenses... 21 5 846 10,046 -- 10,918
Exploration expense........................ -- 55 -- 425 -- 480
------- ------- ------- ------- ------- -------
(129) 696 (846) 14,254 263 14,238
Other income............................... 317 1 1,365 351 (1,340) 694
------- ------- ------- ------- ------- -------
Group replacement cost operating profit.... 188 697 519 14,605 (1,077) 14,932
Share of profits of joint ventures......... -- -- -- 443 -- 443
Share of profits of associated undertakings -- -- -- 760 -- 760
Equity-accounted income of subsidiaries.... 12,460 552 16,761 -- (29,773) --
------- ------- ------- ------- ------- -------
Total replacement cost operating profit.... 12,648 1,249 17,280 15,808 (30,850) 16,135
Profit (loss) on sale of businesses
or termination of operations.............. -- -- (68) -- -- (68)
Profit (loss) on sale of fixed assets...... 517 1 601 760 (1,276) 603
------- ------- ------- ------- ------- -------
Replacement cost profit
before interest and tax................... 13,165 1,250 17,813 16,568 (32,126) 16,670
Inventory holding gains (losses)........... (1,087) (11) (1,900) (1,896) 2,994 (1,900)
------- ------- ------- ------- ------- -------
Historical cost profit
before interest and tax................... 12,078 1,239 15,913 14,672 (29,132) 14,770
Interest expense........................... 1,657 101 2,886 2,567 (5,541) 1,670
------- ------- ------- ------- ------- -------
Profit before taxation..................... 10,421 1,138 13,027 12,105 (23,591) 13,100
Taxation................................... 3,617 272 5,017 4,896 (8,785) 5,017
------- ------- ------- ------- ------- -------
Profit after taxation...................... 6,804 866 8,010 7,209 (14,806) 8,083
Minority shareholders' interest............ -- -- -- 73 -- 73
------- ------- ------- ------- ------- -------
Profit for the year........................ 6,804 866 8,010 7,136 (14,806) 8,010
======= ======= ======= ======= ======= =======
F - 96
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- 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 Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 2001
Profit as reported.......................... 6,804 866 8,010 7,136 (14,806) 8,010
Adjustments:
Deferred taxation/business combinations... (1,611) (265) (2,141) (1,642) 3,518 (2,141)
Provisions................................ (32) (5) (182) (177) 214 (182)
Impairment................................ (911) -- (911) (911) 1,822 (911)
Sale and leaseback........................ (36) -- (36) (36) 72 (36)
Goodwill.................................. (68) -- (68) (68) 136 (68)
Derivative financial instruments.......... (73) -- (313) (313) 386 (313)
Gain arising on asset exchange............ 123 -- 157 157 (280) 157
Other..................................... -- -- 10 10 (10) 10
-------- -------- -------- -------- -------- -------
Profit for the year before cumulative
effect of accounting change as adjusted
to accord with US GAAP................... 4,196 596 4,526 4,156 (8,948) 4,526
Cumulative effect of accounting change:
Derivative financial instruments......... (13) -- (362) (362) 375 (362)
-------- -------- -------- -------- -------- -------
Profit for the year as adjusted to
accord with US GAAP...................... 4,183 596 4,164 3,794 (8,573) 4,164
======== ======== ======== ======== ======== =======
F - 97
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Income statement (continued)
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 2000
Turnover .................................. -- 2,665 -- 161,826 (2,665) 161,826
Less: Joint ventures....................... -- -- -- 13,764 -- 13,764
-------- -------- -------- -------- -------- -------
Group turnover............................. -- 2,665 -- 148,062 (2,665) 148,062
Replacement cost of sales.................. 70 1,126 -- 122,366 (2,842) 120,720
Production taxes........................... -- 276 -- 1,785 -- 2,061
-------- -------- -------- -------- -------- -------
Gross profit............................... (70) 1,263 -- 23,911 177 25,281
Distribution and administration expenses... 1 25 603 8,702 -- 9,331
Exploration expense........................ -- 26 -- 573 -- 599
-------- -------- -------- -------- -------- -------
(71) 1,212 (603) 14,636 177 15,351
Other income............................... 249 (12) 545 562 (539) 805
-------- -------- -------- -------- -------- -------
Group replacement cost
operating profit.......................... 178 1,200 (58) 15,198 (362) 16,156
Share of profits of joint ventures......... -- -- -- 808 -- 808
Share of profits of associated undertakings -- -- -- 792 -- 792
Equity-accounted income of subsidiaries.... 12,519 282 18,155 -- (30,956) --
-------- -------- -------- -------- -------- -------
Total replacement cost operating profit.... 12,697 1,482 18,097 16,798 (31,318) 17,756
Profit (loss) on sale of businesses
or termination of operations.............. (11) -- 26,049 (90) (25,816) 132
Profit (loss) on sale of fixed assets...... 452 (1) 88 111 (562) 88
-------- -------- -------- -------- -------- -------
Replacement cost profit
before interest and tax................... 13,138 1,481 44,234 16,819 (57,696) 17,976
Inventory holding gains (losses)........... 444 (6) 728 728 (1,166) 728
-------- -------- -------- -------- -------- -------
Historical cost profit
before interest and tax................... 13,582 1,475 44,962 17,547 (58,862) 18,704
Interest expense........................... 1,347 22 2,203 1,727 (3,529) 1,770
-------- -------- -------- -------- -------- -------
Profit before taxation..................... 12,235 1,453 42,759 15,820 (55,333) 16,934
Taxation................................... 3,503 552 4,972 4,764 (8,819) 4,972
-------- -------- -------- -------- -------- -------
Profit after taxation...................... 8,732 901 37,787 11,056 (46,514) 11,962
Minority shareholders' interest............ -- -- -- 92 -- 92
-------- -------- -------- -------- -------- -------
Profit for the year........................ 8,732 901 37,787 10,964 (46,514) 11,870
======== ======== ======== ======== ======== =======
F - 98
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- 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 Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 2000
Profit as reported.......................... 8,732 901 37,787 10,964 (46,514) 11,870
Adjustments:
Deferred taxation/business combinations... (1,515) (47) (1,588) (1,426) 2,988 (1,588)
Provisions................................ (24) (18) (68) (50) 92 (68)
Sale and leaseback........................ (34) -- (34) (34) 68 (34)
Goodwill.................................. (48) -- (48) (48) 96 (48)
Other..................................... -- -- 51 51 (51) 51
-------- -------- -------- -------- -------- -------
Profit for the year as adjusted to
accord with US GAAP......................... 7,111 836 36,100 9,457 (43,321) 10,183
======== ======== ======== ======== ======== =======
F - 99
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Income statement (continued)
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
Year ended December 31, 1999
Turnover .................................. -- 2,065 -- 101,180 (2,065) 101,180
Less: Joint ventures....................... -- -- -- 17,614 -- 17,614
-------- -------- -------- -------- -------- -------
Group turnover............................. -- 2,065 -- 83,566 (2,065) 83,566
Replacement cost of sales.................. -- 1,487 -- 69,214 (2,086) 68,615
Production taxes........................... -- 272 -- 745 -- 1,017
-------- -------- -------- -------- -------- -------
Gross profit............................... -- 306 -- 13,607 21 13,934
Distribution and administration expenses... 67 36 473 5,488 -- 6,064
Exploration expense........................ -- 22 -- 526 -- 548
-------- -------- -------- -------- -------- -------
(67) 248 (473) 7,593 21 7,322
Other income............................... 14 -- 465 398 (463) 414
-------- -------- -------- -------- -------- -------
Group replacement cost operating profit.... (53) 248 (8) 7,991 (442) 7,736
Share of profits of joint ventures......... -- -- -- 555 -- 555
Share of profits of associated undertakings -- -- -- 603 -- 603
Equity-accounted income of subsidiaries.... 5,545 134 9,206 -- (14,885) --
-------- -------- -------- -------- -------- -------
Total replacement cost
operating profit.......................... 5,492 382 9,198 9,149 (15,327) 8,894
Profit (loss) on sale of businesses
or termination of operations.............. 2 -- 356 339 (334) 363
Profit (loss) on sale of fixed assets...... 252 -- (700) (700) 448 (700)
Restructuring costs........................ (1,263) (61) (1,943) (1,799) 3,123 (1,943)
-------- -------- -------- -------- -------- -------
Replacement cost profit
before interest and tax................... 4,483 321 6,911 6,989 (12,090) 6,614
Inventory holding gains (losses)........... 858 40 1,728 1,728 (2,626) 1,728
-------- -------- -------- -------- -------- -------
Historical cost profit
before interest and tax................... 5,341 361 8,639 8,717 (14,716) 8,342
Interest expense........................... 985 41 1,758 1,441 (2,909) 1,316
-------- -------- -------- -------- -------- -------
Profit before taxation..................... 4,356 320 6,881 7,276 (11,807) 7,026
Taxation................................... 803 78 1,880 1,881 (2,762) 1,880
-------- -------- -------- -------- -------- -------
Profit after taxation...................... 3,553 242 5,001 5,395 (9,045) 5,146
Minority shareholders' interest............ -- -- -- 138 -- 138
-------- -------- -------- -------- -------- -------
Profit for the year........................ 3,553 242 5,001 5,257 (9,045) 5,008
======== ======== ======== ======== ======== =======
F - 100
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- 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 Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 1999
Profit as reported......................... 3,553 242 5,001 5,257 (9,045) 5,008
Adjustments:
Deferred taxation/business combinations.. (88) 37 (466) (461) 512 (466)
Provisions............................... 27 7 9 (6) (28) 9
Sale and leaseback....................... 62 -- 62 62 (124) 62
Other................................... -- -- (17) (17) 17 (17)
-------- -------- -------- -------- -------- -------
Profit for the year as adjusted to
accord with US GAAP......... 3,554 286 4,589 4,835 (8,668) 4,596
======== ======== ======== ======== ======== =======
F - 101
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Balance sheet
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
At December 31, 2001
Fixed assets
Intangible assets.......................... 1,190 489 -- 15,104 (1,190) 15,593
Tangible assets............................ -- 6,418 -- 70,992 -- 77,410
Investments
Joint ventures.......................... -- -- -- 3,861 -- 3,861
Associated undertakings................. -- -- 3 5,564 -- 5,567
Other................................... -- -- 266 2,353 -- 2,619
Subsidiaries - equity accounted basis... 72,879 1,941 86,083 -- (160,903) --
-------- -------- -------- -------- -------- -------
72,879 1,941 86,352 11,778 (160,903) 12,047
-------- -------- -------- -------- -------- -------
Total fixed assets......................... 74,069 8,848 86,352 97,874 (162,093) 105,050
-------- -------- -------- -------- -------- -------
Current assets
Business held for resale................... -- -- -- -- -- --
Inventories................................ 5 92 -- 7,534 -- 7,631
Receivables - amounts falling due:
Within one year......................... 2,090 132 2,700 28,745 (11,679) 21,988
After more than one year................ 5,597 15,201 18,572 19,905 (54,594) 4,681
Investments................................ 22 -- -- 428 -- 450
Cash at bank and in hand................... (2) (29) 3 1,386 -- 1,358
-------- -------- -------- -------- -------- -------
7,712 15,396 21,275 57,998 (66,273) 36,108
-------- -------- -------- -------- -------- -------
Current liabilities - amounts falling
due within one year
Finance debt............................... 5,190 406 -- 6,302 (2,808) 9,090
Other payables............................. 89 252 7,642 29,707 (9,166) 28,524
-------- -------- -------- -------- -------- -------
Net current assets (liabilities) 2,433 14,738 13,633 21,989 (54,299) (1,506)
-------- -------- -------- -------- -------- -------
Total assets less current liabilities 76,502 23,586 99,985 119,863 (216,392) 103,544
Noncurrent liabilities
Finance debt............................... 4,394 -- -- 11,991 (4,058) 12,327
Other payables............................. 824 10,795 191 41,812 (50,536) 3,086
Provisions for liabilities and charges
Deferred taxation.......................... -- -- -- 1,655 -- 1,655
Other...................................... 48 387 216 10,831 -- 11,482
-------- -------- -------- -------- -------- -------
Net assets................................. 71,236 12,404 99,578 53,574 (161,798) 74,994
Minority shareholders' interest - equity... -- -- -- 627 -- 627
-------- -------- -------- -------- -------- -------
BP shareholders' interest.................. 71,236 12,404 99,578 52,947 (161,798) 74,367
======== ======== ======== ======== ======== =======
F - 102
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Balance sheet (continued)
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
At December 31, 2001
Capital and reserves
Capital shares............................ 8 1,050 5,629 -- (1,058) 5,629
Paid in surplus........................... 32,267 3,145 4,014 -- (35,412) 4,014
Merger reserve............................ -- -- 26,286 697 -- 26,983
Other reserves............................ -- -- 223 -- -- 223
Retained earnings......................... 38,961 8,209 63,426 52,250 (125,328) 37,518
-------- -------- -------- -------- -------- -------
71,236 12,404 99,578 52,947 (161,798) 74,367
======== ======== ======== ======== ======== =======
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 Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
BP shareholders' interest as reported...... 71,236 12,404 99,578 52,947 (161,798) 74,367
Adjustments:
Deferred taxation/business combinations.. (8,626) (1,573) (10,029) (8,287) 18,486 (10,029)
Provisions............................... (585) (186) (1,054) (1,141) 1,912 (1,054)
Sale and leaseback....................... (134) -- (134) (134) 268 (134)
Goodwill................................. (348) -- (348) (348) 696 (348)
Derivative financial instruments......... (86) -- (675) (675) 761 (675)
Gain arising on asset exchange........... 123 -- 157 157 (280) 157
Ordinary shares held for future awards
to employees............................ -- -- (266) (266) 266 (266)
Dividends................................ -- -- 1,288 1,288 (1,288) 1,288
Investments.............................. 32 -- (2) (2) (30) (2)
Additional minimum pension liability..... (912) -- (942) (942) 1,854 (942)
Other.................................... -- -- (40) (40) 40 (40)
-------- -------- -------- -------- -------- -------
BP shareholders' interest as adjusted
to accord with US GAAP.................... 60,700 10,645 87,533 42,557 (139,113) 62,322
-------- -------- -------- -------- -------- -------
F - 103
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Balance sheet (continued)
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
At December 31, 2000
Fixed assets
Intangible assets.......................... 1,330 512 -- 16,381 (1,330) 16,893
Tangible assets............................ 7 5,942 -- 69,224 -- 75,173
Investments
Joint ventures.......................... -- -- -- 2,884 -- 2,884
Associated undertakings................. -- -- 3 5,452 -- 5,455
Other................................... -- -- 360 3,054 -- 3,414
Subsidiaries - equity accounted basis... 66,114 619 77,826 -- (144,559) --
-------- -------- -------- -------- -------- -------
66,114 619 78,189 11,390 (144,559) 11,753
-------- -------- -------- -------- -------- -------
Total fixed assets......................... 67,451 7,073 78,189 96,995 (145,889) 103,819
-------- -------- -------- -------- -------- -------
Current assets
Business held for resale................... -- -- -- 636 -- 636
Inventories................................ -- 75 -- 9,159 -- 9,234
Receivables - amounts falling due:
Within one year......................... 1,788 1,335 3,929 23,490 (6,734) 23,808
After more than one year................ 10,004 13,576 19,466 5,782 (44,218) 4,610
Investments................................ 5 -- -- 656 -- 661
Cash at bank and in hand................... -- (32) 2 1,200 -- 1,170
-------- -------- -------- -------- -------- -------
11,797 14,954 23,397 40,923 (50,952) 40,119
-------- -------- -------- -------- -------- -------
Current liabilities - amounts falling
due within one year
Finance debt............................... 8,531 -- -- 5,969 (8,082) 6,418
Other payables............................. 119 644 2,582 38,784 (10,019) 32,110
-------- -------- -------- -------- -------- -------
Net current assets (liabilities) 3,147 14,310 20,815 (3,830) (32,851) 1,591
-------- -------- -------- -------- -------- -------
Total assets less current liabilities 70,598 21,383 99,004 93,165 (178,740) 105,410
Noncurrent liabilities
Finance debt............................... 870 1,150 -- 13,902 (1,150) 14,772
Other payables............................. 5,246 9,482 178 18,820 (29,884) 3,842
Provisions for liabilities
and charges
Deferred taxation.......................... -- (5) -- 1,827 -- 1,822
Other...................................... 49 269 197 10,458 -- 10,973
-------- -------- -------- -------- -------- -------
Net assets................................. 64,433 10,487 98,629 48,158 (147,706) 74,001
Minority shareholders' interest - equity... -- -- -- 585 -- 585
-------- -------- -------- -------- -------- -------
BP shareholders' interest.................. 64,433 10,487 98,629 47,573 (147,706) 73,416
======== ======== ======== ======== ======== =======
F - 104
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Balance sheet (concluded)
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
At December 31, 2000
Capital and reserves
Capital shares........................... 8 -- 5,653 -- (8) 5,653
Paid in surplus.......................... 32,267 3,145 3,770 -- (35,412) 3,770
Merger reserve........................... -- -- 26,172 697 -- 26,869
Other reserves........................... -- -- 456 -- -- 456
Retained earnings........................ 32,158 7,342 62,578 46,876 (112,286) 36,668
-------- -------- -------- -------- -------- -------
64,433 10,487 98,629 47,573 (147,706) 73,416
======== ======== ======== ======== ======== =======
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 Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
BP shareholders' interest as reported....... 64,433 10,487 98,629 47,573 (147,706) 73,416
Adjustments:
Deferred taxation/business combinations... (7,141) (1,353) (7,983) (6,949) 15,443 (7,983)
Provisions................................ (716) (183) (913) (497) 1,396 (913)
Sale and leaseback........................ (104) -- (104) (104) 208 (104)
Goodwill.................................. 631 -- 631 631 (1,262) 631
Ordinary shares held for future awards
to employees............................. -- -- (360) (360) 360 (360)
Dividends................................. -- -- 1,178 1,178 (1,178) 1,178
Investments............................... (52) -- (112) (112) 164 (112)
Additional minimum pension liability...... (25) -- (145) (145) 170 (145)
Other..................................... -- -- (94) (54) 94 (54)
-------- -------- -------- -------- -------- -------
BP shareholders' interest as adjusted
to accord with US GAAP..................... 57,026 8,951 90,727 41,161 (132,311) 65,554
======== ======== ======== ======== ======== =======
F - 105
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Cash flow statement
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 2001
Net cash inflow (outflow) from
operating activities....................... 306 956 6,199 17,943 (2,995) 22,409
Dividends from joint ventures............... -- -- -- 104 -- 104
Dividends from associated undertakings...... -- -- -- 528 -- 528
Dividends from subsidiaries................. 925 -- 1,537 -- (2,462) --
Net cash inflow (outflow) from servicing
of finance and returns on investments...... (32) -- 1,218 (2,134) -- (948)
Tax paid ................................... (1,682) (345) (1) (2,632) -- (4,660)
Net cash inflow (outflow) for capital
expenditure and financial investment....... (717) (1,870) (33) (7,229) -- (9,849)
Net cash inflow for acquisitions
and disposals.............................. -- -- (2,995) (1,755) 2,995 (1,755)
Equity dividends paid....................... -- -- (4,827) (2,462) 2,462 (4,827)
-------- -------- -------- -------- -------- -------
Net cash inflow (outflow)................... (1,200) (1,259) 1,098 2,363 -- 1,002
======== ======== ======== ======== ======== =======
Financing................................... (1,198) (1,262) 1,097 2,335 -- 972
Management of liquid resources.............. -- -- -- (211) -- (211)
Increase in cash............................ (2) 3 1 239 -- 241
-------- -------- -------- -------- -------- -------
(1,200) (1,259) 1,098 2,363 -- 1,002
======== ======== ======== ======== ======== =======
The consolidated statement of cash flows presented in accordance with SFAS 95 is
as follows:
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
Net cash provided by (used in)
operating activities.................... (483) 611 8,953 13,809 (5,322) 17,568
Net cash provided by (used in)
investing activities.................... (717) (1,870) (3,028) (8,984) 2,914 (11,685)
Net cash provided by (used in)
financing activities.................... 1,198 1,262 (5,924) (4,797) 2,408 (5,853)
Currency translation differences relating
to cash and cash equivalents............ -- -- -- (53) -- (53)
-------- -------- -------- -------- -------- -------
Increase (decrease) in cash and
cash equivalents........................ (2) 3 1 (25) -- (23)
Cash and cash equivalents
at beginning of year.................... -- (32) 2 1,861 -- 1,831
-------- -------- -------- -------- -------- -------
Cash and cash equivalents
at end of year.......................... (2) (29) 3 1,836 -- 1,808
======== ======== ======== ======== ======== =======
F - 106
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(continued)
Cash flow statement (continued)
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 2000
Net cash inflow (outflow) from
operating activities...................... (460) 1,683 (12,830) 8,418 23,605 20,416
Dividends from joint ventures.............. -- -- -- 645 -- 645
Dividends from associated undertakings..... -- -- -- 394 -- 394
Dividends from subsidiaries................ 899 -- 793 -- (1,692) --
Net cash inflow (outflow) from servicing
of finance and returns on investments..... (216) (1) 431 (1,106) -- (892)
Tax paid .................................. (397) (754) 5 (5,052) -- (6,198)
Net cash inflow (outflow) for capital......
expenditure and financial investment...... -- (552) (64) (6,456) -- (7,072)
Net cash inflow for acquisitions
and disposals............................. 12 45 18,118 6,295 (23,605) 865
Equity dividends paid...................... -- -- (4,415) (1,692) 1,692 (4,415)
-------- -------- -------- -------- -------- -------
Net cash inflow (outflow).................. (162) 421 2,038 1,446 -- 3,743
======== ======== ======== ======== ======== =======
Financing.................................. (95) 435 2,039 1,034 -- 3,413
Management of liquid resources............. -- -- -- 452 -- 452
Increase in cash........................... (67) (14) (1) (40) -- (122)
-------- -------- -------- -------- -------- -------
(162) 421 2,038 1,446 -- 3,743
======== ======== ======== ======== ======== =======
The consolidated statement of cash flows presented in accordance with SFAS 95 is
as follows:
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
Net cash provided by (used in)
operating activities....................... (174) 928 (11,601) 3,395 22,056 14,604
Net cash provided by (used in)
investing activities....................... 11 (507) 18,054 (161) (23,723) (6,326)
Net cash provided by (used in)
financing activities....................... 96 (435) (6,454) (2,726) 1,667 (7,852)
Currency translation differences relating
to cash and cash equivalents............... -- -- -- (50) -- (50)
-------- -------- -------- -------- -------- -------
Increase (decrease) in cash and
cash equivalents........................... (67) (14) (1) 458 -- 376
Cash and cash equivalents
at beginning of year....................... 67 (18) 3 1,403 -- 1,455
-------- -------- -------- -------- -------- -------
Cash and cash equivalents
at end of year............................. -- (32) 2 1,861 -- 1,831
======== ======== ======== ======== ======== =======
F - 107
NOTES TO FINANCIAL STATEMENTS (Continued)
Note 47 -- Condensed consolidating information on certain US subsidiaries
(concluded)
Cash flow statement (concluded)
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
For the year ended December 31, 1999
Net cash inflow from
operating activities...................... 10 739 282 10,468 (1,209) 10,290
Dividends from joint ventures.............. -- -- -- 949 -- 949
Dividends from associated undertakings..... -- -- -- 219 -- 219
Dividends from subsidiaries................ -- -- 4,577 -- (4,577) --
Net cash inflow (outflow) from servicing
of finance and returns on investments..... (375) -- 438 (1,066) -- (1,003)
Tax paid .................................. 124 (62) (119) (1,203) -- (1,260)
Net cash inflow (outflow) for capital
expenditure and financial investment...... -- (393) (77) (4,915) -- (5,385)
Net cash inflow (outflow) for
acquisitions and disposals................ 11 1 (1,209) 231 1,209 243
Equity dividends paid...................... -- -- (4,135) (4,577) 4,577 (4,135)
-------- -------- -------- -------- -------- -------
Net cash inflow (outflow).................. (230) 285 (243) 106 -- (82)
======== ======== ======== ======== ======== =======
Financing.................................. (298) 273 (245) (684) -- (954)
Management of liquid resources............. -- -- -- (93) -- (93)
Increase in cash........................... 68 12 2 883 -- 965
-------- -------- -------- -------- -------- -------
(230) 285 (243) 106 -- (82)
======== ======== ======== ======== ======== =======
The consolidated statement of cash flows presented in accordance with SFAS 95 is
as follows:
Issuer Issuer Guarantor
-------------------------------------
BP Eliminations
BP America Exploration BP Other and BP
Inc. (Alaska) Inc. p.l.c. subsidiaries reclassifications Group
---------- ------------ -------- ------------ ----------------- ------
($ million)
Net cash provided by (used in)
operating activities....................... (240) 677 5,178 9,141 (5,856) 8,900
Net cash provided by (used in)
investing activities....................... 10 (392) (1,286) (4,684) 1,430 (4,922)
Net cash provided by (used in)
financing activities....................... 298 (273) (3,890) (3,893) 4,426 (3,332)
Currency translation differences relating
to cash and cash equivalents............... -- -- -- 15 -- 15
-------- -------- -------- -------- -------- -------
Increase (decrease) in cash and
cash equivalents........................... 68 12 2 579 -- 661
Cash and cash equivalents
at beginning of year....................... (1) (30) 1 824 -- 794
-------- -------- -------- -------- -------- -------
Cash and cash equivalents
at end of year............................. 67 (18) 3 1,403 -- 1,455
======== ======== ======== ======== ======== =======
F - 108
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, 2001, 2000 and 1999.
Estimated net proved reserves of crude oil (a)
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 7,217
======== ======== ======== ======== ========
Equity-accounted entities
BP share
At January 1..................................................................... 1,135
Net revisions and other additions.............................................. 100
Production..................................................................... (76)
------
At December 31................................................................... 1,159
======
Total Group and BP share of equity-accounted entities........................... 8,376
======
F - 109
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
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 1,047 6,535
======== ======== ======== ======== ========
Changes in year attributable to:
Revisions of previous estimates...... 17 50 40 5 112
Purchases of reserves-in-place....... 146 -- 554 441 1,141
Extensions, discoveries and
other additions.................... 1 -- 255 201 457
Improved recovery.................... 131 71 105 22 329
Production........................... (195) (33) (251) (143) (622)
Sales of reserves-in-place........... (49) -- (1,372) (23) (1,444)
-------- -------- -------- -------- --------
51 88 (669) 503 (27)
======== ======== ======== ======== ========
At December 31
Developed............................ 1,138 213 2,150 817 4,318
Undeveloped.......................... 254 160 1,043 733 2,190
-------- -------- -------- -------- --------
1,392 373 3,193(b) 1,550 6,508
======== ======== ======== ======== ========
Equity-accounted entities
BP share
At January 1..................................................................... 1,037
Net revisions and other additions.............................................. 93
Purchases of reserves-in-place................................................. 73
Production..................................................................... (68)
------
At December 31................................................................... 1,135
======
Total Group and BP share of equity-accounted entities........................... 7,643
======
F - 110
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Estimated net proved reserves of crude oil (a) (concluded)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(millions of barrels)
1999
Subsidiary undertakings
At January 1
Developed............................... 1,258 220 2,982 858 5,318
Undeveloped............................. 270 51 979 686 1,986
-------- -------- -------- -------- --------
1,528 271 3,961 1,544 7,304
======== ======== ======== ======== ========
Changes in year attributable to:
Revisions of previous estimates........... (10) 12 11 1 14
Purchases of reserves-in-place............ 6 -- 4 -- 10
Extensions, discoveries and other additions 1 24 100 44 169
Improved recovery......................... 28 14 87 83 212
Production................................ (212) (36) (275) (149) (672)
Sales of reserves-in-place................ -- -- (33) (476) (509)
Transfers from equity-accounted entities.. -- -- 7(d) -- 7
-------- -------- -------- -------- --------
(187) 14 (99) (497) (769)
======== ======== ======== ======== ========
At December 31
Developed............................... 1,158 190 2,930 550 4,828
Undeveloped............................. 183 95 932 497 1,707
-------- -------- -------- -------- --------
1,341 285 3,862(b)(c) 1,047 6,535
======== ======== ======== ======== ========
Equity-accounted entities
BP share
At January 1..................................................................... 1,128
Net revisions and other additions.............................................. (21)
Production..................................................................... (63)
Transfers to subsidiary undertakings........................................... (7)(d)
------
At December 31................................................................... 1,037
======
Total Group and BP share of equity-accounted entities........................... 7,572
======
----------
(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 43
million barrels (91 million barrels at December 31, 2000 and 94 million
barrels at December 31, 1999) 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.
Equity-accounted entities
(d) Transfer from equity-accounted entities to subsidiary undertakings comprise
reserves in Crescendo Resources after the acquisition of the majority
interest from Repsol-YPF.
F - 111
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Estimated net proved reserves of natural gas (a)
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 42,959
======== ======== ======== ======== ========
Equity-accounted entities
BP share
At January 1..................................................................... 2,818
Net revisions and other additions.............................................. 523
Production..................................................................... (125)
------
At December 31................................................................... 3,216
======
Total Group and BP share of equity-accounted entities........................... 46,175
======
F - 112
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
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 17,193 33,802
======== ======== ======== ======== ========
Changes in year attributable to:
Revisions of previous estimates...... (17) 23 150 331 487
Purchases of reserves-in-place....... 1,099 -- 3,034 2,313 6,446
Extensions, discoveries and
other additions.................... 253 -- 923 2,343 3,519
Improved recovery.................... 29 28 980 91 1,128
Production........................... (605) (50) (1,174)(b) (916) (2,745)
Sales of reserves-in-place........... (76) -- (1,393) (68) (1,537)
-------- -------- -------- -------- --------
683 1 2,520 4,094 7,298
======== ======== ======== ======== ========
At December 31
Developed............................ 3,898 275 12,111 7,985 24,269
Undeveloped.......................... 1,058 71 2,400 13,302 16,831
-------- -------- -------- -------- --------
4,956 346 14,511 21,287 41,100
======== ======== ======== ======== ========
Equity-accounted entities
BP share
At January 1..................................................................... 1,724
Net revisions and other additions.............................................. 427
Purchases of reserves-in-place................................................. 763
Production..................................................................... (96)
------
At December 31................................................................... 2,818
======
Total Group and BP share of equity-accounted entities........................... 43,918
======
F - 113
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Estimated net proved reserves of natural gas (a) (concluded)
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
billions of cubic feet)
1999
Subsidiary undertakings
At January 1
Developed............................ 3,536 324 9,637 6,054 19,551
Undeveloped.......................... 1,107 38 1,658 8,647 11,450
-------- -------- -------- -------- --------
4,643 362 11,295 14,701 31,001
======== ======== ======== ======== ========
Changes in year attributable to:
Revisions of previous estimates...... 1 9 215 (107) 118
Purchases of reserves-in-place....... 3 -- -- 12 15
Extensions, discoveries and
other additions.................... 79 34 417 3,296 3,826
Improved recovery.................... 22 -- 242 299 563
Production........................... (475) (60) (907)(b) (752) (2,194)
Sales of reserves-in-place........... -- -- (143) (256) (399)
Transfers from equity-accounted
entities........................... -- -- 872(d) -- 872
-------- -------- -------- -------- --------
(370) (17) 696 2,492 2,801
======== ======== ======== ======== ========
At December 31
Developed............................ 3,354 282 10,439 6,423 20,498
Undeveloped.......................... 919 63 1,552 10,770 13,304
-------- -------- -------- -------- --------
4,273 345 11,991(c) 17,193 33,802
======== ======== ======== ======== ========
Equity-accounted entities
BP share
At January 1..................................................................... 1,766
Net revisions and other additions.............................................. 549
Purchases of reserves-in-place................................................. 378
Production..................................................................... (97)
Transfers to subsidiary undertakings........................................... (872)(d)
------
At December 31................................................................... 1,724
======
Total Group and BP share of equity-accounted entities........................... 35,526
======
----------
(a) Net proved reserves of natural gas exclude production royalties due to
others.
(b) Includes 61 billion cubic feet of natural gas consumed in Alaskan
operations (2000, 55 billion cubic feet and 1999, 77 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.
Equity-accounted entities
(d) Transfers from equity-accounted entities to subsidiary undertakings
comprise reserves in Crescendo Resources after the acquisition of the
majority interest from Repsol-YPF.
F - 114
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, 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
======== ======= ======== ======== ========
At December 31, 1999
Future cash inflows (a).................... 42,400 7,900 101,500 49,500 201,300
Future production and development costs (b) 18,800 2,000 32,500 13,700 67,000
Future taxation (c)........................ 5,900 4,200 23,300 15,800 49,200
-------- ------- -------- -------- --------
Future net cash flows...................... 17,700 1,700 45,700 20,000 85,100
10% annual discount (d).................... 4,700 400 23,200 8,400 36,700
-------- ------- -------- -------- --------
Standardized measure of discounted future
net cash flows........................... 13,000 1,300 22,500 11,600 48,400
======== ======= ======== ======== ========
F - 115
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,
2001, 2000 and 1999:
Years ended December 31,
------------------------
2001 2000 1999
------ ------ ------
($ million)
Sales and transfers of oil and gas produced, net of
production costs...................................... (17,500) (18,400) (12,600)
Development costs incurred during the year.............. 6,800 4,500 2,900
Extensions, discoveries and improved recovery,
less related costs.................................... 9,200 13,100 6,200
Net changes in prices and production costs (e).......... (74,100) 51,100 47,900
Revisions of previous reserve estimates................. (1,300) 900 2,600
Net change in taxation.................................. 26,300 (14,800) (18,000)
Future development costs................................ (3,200) (2,400) (200)
Net change in purchase and sales of reserves-in-place... (200) 2,400 (900)
Addition of 10% annual discount......................... 8,900 4,800 1,900
------ ------ ------
Total change in the standardized measure during the year (45,100) 41,200 29,800
====== ====== ======
----------
(a) Future cash inflows are computed by applying year-end oil and natural gas
prices and exchange rates to future annual production levels estimated by
the Group's petroleum engineers.
(b) Production costs (which include petroleum revenue tax in the UK) and
development costs relating to future production of proved reserves are
based on year-end cost levels and assume continuation of existing economic
conditions. Future decommissioning costs are included.
(c) Taxation is computed using appropriate year-end income tax rates.
(d) Future net cash flows from oil and natural gas production are discounted at
10% regardless of the Group assessment of the risk associated with its
producing activities.
(e) Net changes in prices and production costs includes the effect of exchange
movements.
Equity-accounted entities
In addition, at December 31, 2001 the Group's share of the standardized
measure of discounted future net cash flows of equity-accounted entities
amounted to $3,400 million ($3,100 million at December 31, 2000 and $2,420
million at December 31, 1999).
F - 116
SUPPLEMENTARY OIL AND GAS INFORMATION (Continued)
(Unaudited)
Operational and statistical information
The following tables present operational and statistical information
related to production, drilling, productive wells and acreage.
Produced from own reserves
The following table shows crude oil and natural gas production from the
Group's own reserves for the years indicated:
Rest of Rest of
UK Europe USA World Total(d)
-------- -------- -------- -------- --------
(thousand barrels per day)
Production for the year (a)
Crude oil (b)
2001................................... 485 100 744 602 1,931
2000................................... 534 90 729 575 1,928
1999................................... 580 100 804 577 2,061
Rest of Rest of
UK Europe USA World Total(e)
-------- -------- -------- -------- --------
(million cubic feet per day)
Natural gas (c)
2001................................... 1,713 147 3,554 3,218 8,632
2000................................... 1,652 136 3,054 2,767 7,609
1999................................... 1,301 164 2,369 2,233 6,067
----------
(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
208,000 b/d in 2001 (2000, 185,000 b/d and 1999, 170,000 b/d).
(e) Includes amounts produced for the Group by equity-accounted entities of 345
mmcf/d in 2001 (2000, 263 mmcf/d and 1999, 264 mmcf/d).
F - 117
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, 2001. A 'gross' well or acre is one in which a
whole or fractional working interest is owned, while the number of 'net' wells
or acres is the sum of the whole or fractional working interests in gross wells
or acres. Productive wells are producing wells and wells capable of production.
Developed acreage is the acreage within the boundary of a field, on which
development wells have been drilled, which could produce the reserves; while
undeveloped acres are those on which wells have not been drilled or completed to
a point that would permit the production of commercial quantities, whether or
not such acres contain proved reserves.
Number of productive oil and gas wells
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
At December 31, 2001
Oil wells (a) -- gross................ 457 77 7,804 11,085 19,423
-- net................... 229.4 28.0 4,565.9 2,942.9 7,766.2
Gas wells (b) -- gross................. 540 39 19,995 2,829 23,403
-- net................... 218.4 13.4 11,734.1 1,568.1 13,534.0
----------
(a) Includes approximately 2,045 gross (924.8 net) multiple completion wells
(more than one formation producing into the same well bore).
(b) Includes 2,081 gross (1,210.8 net) multiple completion wells.
(c) If one of the multiple completions in a well is an oil completion, the well
is classified as an oil well.
Oil and natural gas acreage
Rest of Rest of
UK Europe USA World Total
-------- -------- -------- -------- --------
(thousands of acres)
At December 31, 2001
Developed
-- gross............................. 767 133 13,471 6,927 21,298
-- net............................... 341.7 45.3 5,782.4 2,145.0 8,314.4
Undeveloped (a)
-- gross............................. 4,708 3,975 10,330 99,509 118,522
-- net............................... 2,330.7 1,435.7 5,690.9 42,336.7 51,794.0
----------
(a) Undeveloped acreage includes leases and concessions.
F - 118
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
-------- -------- -------- -------- --------
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
1999
Exploratory
-- productive........................ 0.5 0.5 3.7 10.1 14.8
-- dry............................... 1.1 0.9 1.4 6.6 10.0
Development
-- productive........................ 27.3 1.3 274.4 160.6 463.6
-- dry............................... 1.7 0.3 10.5 15.4 27.9
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, 2001. 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, 2001
Exploratory
-- gross............................. -- 3 9 20 32
-- net............................... -- 0.8 3.5 7.2 11.5
Development
-- gross............................. 20 3 78 95 196
-- net............................... 9.7 0.8 43.2 20.7 74.4
F - 119
SCHEDULE II
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)
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
========== ========== ========== ========== ==========
1999
Fixed assets -- Investments (b) 230 83 (2) (2) 309
========== ========== ========== ========== ==========
Doubtful debts (b)............ 126 12 (13) (8) 117
========== ========== ========== ========== ==========
Decommissioning provisions.... 3,310 80 (472) (133) 2,785
========== ========== ========== ========== ==========
----------
(a) Principally currency translations, apart from 1999 for decommissioning
provisions which includes the impact of adopting FRS 12. 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