Annual Report and
Form 20-F 2013
bp.com/annualreport
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Building a stronger,
safer BP
Who we are
BP is one of the world’s leading integrated oil and
gas companies.a We aim to create long-term value
for shareholders by helping to meet growing
demand for energy in a safe and responsible way.
We strive to be a world-class operator, a responsible
corporate citizen and a good employer.
Through our work we provide
customers with fuel for transportation,
energy for heat and light, lubricants
to keep engines moving and the
petrochemicals products used to make
everyday items as diverse as paints,
clothes and packaging. Our projects
and operations help to generate
employment, investment and tax
revenues in countries and communities
around the world. We employ more
than 80,000 people, mostly in Europe
and the US.
As a global group, our interests
and activities are held or operated
through subsidiaries, branches, joint
arrangements or associates established
in – and subject to the laws and
regulations of – many different
jurisdictions. The UK is a centre for
trading, legal, finance, research and
technology and other business
functions. We have well-established
operations in Europe, the US, Canada,
Russia, South America, Australasia,
Asia and parts of Africa.
a On the basis of market capitalization, proved reserves
and production.
Annual Report and
Form 20-F 2013
bp.com/annualreport
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Building a stronger,
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BP Annual Report and Form 20-F 2013
Front cover imagery
Our second BP-operated development in Angola
consists of four oil fields – Plutão, Saturno, Vénus
and Marte (PSVM).
Left image: the converted hull, floating,
production, storage and offloading vessel (FPSO)
has 1.6 million barrels of storage capacity.
Centre image: a PSVM mechanical technician
takes part in a site visit on board the vessel.
Right image: the hawser is a 75 metre rope that
we use to tie the tanker to the back of the FPSO.
Your feedback
We welcome your comments and feedback on
our reporting. Your views are important to us
and help us shape our reporting for future years.
You can provide this at
bp.com/annualreportfeedback or by emailing or
writing to the corporate reporting team. Details
are on the back cover. For every survey
completed, we will make a £2 donation to the
British Paralympic Association.
BP in 2013
Our actions continue to make
BP stronger and safer. We are
growing shareholder returns
through operational efficiency
and financial discipline. We
report on our progress here.
Information about this report
1 Strategic report
2
6
8
10
12
13
18
20
22
BP at a glance
Chairman’s letter
Group chief executive’s letter
Our market outlook
Our business model
Our strategy
Our key performance indicators
Our approach to executive directors’
remuneration
Group performance
59 Corporate governance
60
66
69
71
72
73
74
Board of directors
Executive team
Governance overview
How the board works
Board effectiveness
Shareholder engagement
Audit committee
Upstream
Downstream
Rosneft
Other businesses and corporate
Gulf of Mexico oil spill
Corporate responsibility
Our management of risk
Risk factors
Liquidity and capital resources
25
31
35
37
38
41
49
51
56
77
Safety, ethics and environment
assurance committee
Gulf of Mexico committee
Nomination committee
Chairman’s committee
Directors’ remuneration report
78
79
80
81
109 Regulatory information
115 Financial statements
116 Statement of directors’ responsibilities
117
Consolidated financial statements
of the BP group
126 Notes on financial statements
200
224
Supplementary information on oil and
natural gas (unaudited)
Parent company financial statements
of BP p.l.c.
235 Additional disclosures
236 Selected financial information
239 Upstream analysis by region
242 Downstream analysis by region
245 Oil and gas disclosures for the group
252 Environmental expenditure
252 Contractual obligations
253 Regulation of the group’s business
257 Legal proceedings
267 Further note on certain activities
268 Material contracts
268 Property, plant and equipment
268 Related-party transactions
269 Exhibits
269 Certain definitions
271 Directors’ report information
271 Cautionary statement
273 Shareholder information
274 Called-up share capital
274 Share prices and listings
274 Dividends
275 UK foreign exchange controls on dividends
275 Shareholder taxation information
277 Major shareholders
278
Purchases of equity securities by the
issuer and affiliated purchasers
278 Fees and charges payable by
279
ADSs holders
Fees and payments made by
the Depositary to the issuer
279 Documents on display
280 Administration
280 Annual general meeting
282 Cross reference to Form 20-F
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Strategic reportBP Annual Report and Form 20-F 2013
Information about this report
Cautionary statement
This document should be read in conjunction
with the cautionary statement on page 271.
Frequent abbreviations
ADR
American depositary receipt.
ADS
American depositary share.
Barrel (bbl)
159 litres, 42 US gallons.
bcf
Billion cubic feet.
bcf/d
Billion cubic feet per day.
bcfe
Billion cubic feet equivalent.
bcma
Billion cubic metres per annum.
b/d
Barrels per day.
boe
Barrels of oil equivalent.
GAAP
Generally accepted accounting practice.
Gas
Natural gas.
Hydrocarbons
Liquids and natural gas.
IFRS
International Financial Reporting Standards.
Liquids
Crude oil, condensate and natural gas liquids.
LNG
Liquefied natural gas.
LPG
Liquefied petroleum gas.
mb/d
Thousand barrels per day.
mboe/d
Thousand barrels of oil equivalent per day.
mmboe
Million barrels of oil equivalent.
mmBtu
Million British thermal units.
mmcf
Million cubic feet.
mmcf/d
Million cubic feet per day.
MW
Megawatt.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
RC
Replacement cost.
SEC
The United States Securities and
Exchange Commission.
Therm
100,000 British thermal units.
Tonne
2,204.6 pounds.
Certain definitions
For definitions of certain financial and
contractual terms see page 269.
Key performance indicators (KPIs)
Read about our group KPIs on page 18.
ii
This document constitutes the Annual Report and Accounts in accordance with UK requirements
and the Annual Report on Form 20-F in accordance with the US Securities Exchange Act of 1934, for
BP p.l.c. for the year ended 31 December 2013. A cross reference to Form 20-F requirements is
included on page 282.
The BP Annual Report and 20-F 2013 reflects a number of significant changes in regulations in the
UK. The most significant change is the requirement to produce a new strategic report that replaces
the previous business review. The regulations require certain new disclosures to be included in the
strategic report including a description of a company’s strategy and business model – we have
included a more focused and graphical presentation of BP’s strategy and business model in this
report, compared with the 2012 report.
This document contains the Strategic report on pages 1-58 and the inside cover (Who we are
section) and the Directors’ report on pages 59-80, 109-114, 116, 200-223 and 235-280. The Strategic
report and the Directors’ report together include the management report required by DTR 4.1 of the
UK Financial Conduct Authority’s Disclosure and Transparency Rules. The Directors’ remuneration
report is on pages 81-108. The consolidated financial statements of the group are on pages 115-199
and the corresponding reports of the auditor are on pages 117-121. The parent company financial
statements of BP p.l.c. and corresponding auditor’s report are on pages 224-234 and page 224
respectively.
The statement of directors’ responsibilities, the independent auditor’s report on the annual report
and accounts to the members of BP p.l.c. and the parent company financial statements of BP p.l.c.
and corresponding auditor’s report do not form part of BP’s Annual Report on Form 20-F as filed
with the SEC.
BP Annual Report and Form 20-F 2013 and BP Strategic Report 2013 (comprising the Strategic report
and supplementary information) may be downloaded from bp.com/annualreport. No material on the
BP website, other than the items identified as BP Annual Report and Form 20-F 2013 or
BP Strategic Report 2013 (comprising the Strategic report and supplementary information), forms any
part of those documents. References in this document to other documents on the BP website, such
as the BP Energy Outlook, are included as an aid to their location and are not incorporated by
reference into this document.
BP p.l.c. is the parent company of the BP group of companies. The company was incorporated in
1909 in England and Wales and changed its name to BP p.l.c. in 2001. Where we refer to the
company, we mean BP p.l.c. Unless otherwise stated, the text does not distinguish between the
activities and operations of the parent company and those of its subsidiaries, and information in this
document reflects 100% of the assets and operations of the company and its subsidiaries that were
consolidated at the date or for the periods indicated, including non-controlling interests.
BP’s primary share listing is the London Stock Exchange. Ordinary shares are also traded on the
Frankfurt Stock Exchange in Germany and, in the US, the company’s securities are traded on the
New York Stock Exchange (NYSE) in the form of ADSs (see page 274 for more details).
The term ‘shareholder’ in this report means, unless the context otherwise requires, investors in the
equity capital of BP p.l.c., both direct and indirect. As BP shares, in the form of ADSs, are listed on the
NYSE, an Annual Report on Form 20-F is filed with the US Securities and Exchange Commission (SEC).
Ordinary shares are ordinary fully paid shares in BP p.l.c. of 25 cents each. Preference shares are
cumulative first preference shares and cumulative second preference shares in BP p.l.c. of £1 each.
Trade marks of the BP group appear throughout this Annual Report and Form 20-F in italics.
They include:
Aral
ARCO
BP
Castrol
Castrol EDGE
Field of the Future
Fluid Strength Technology
Hummingbird
LoSal
Project 20K
SaaBre
Veba Combi-Cracking (VCC)
Permasense is a trade mark of Permasense
Limited.
Pick n Pay is a registered trademark of
Pick n Pay Stores Limited.
Registered office and our worldwide
headquarters:
Our agent in the US:
BP p.l.c.
1 St James’s Square
London SW1Y 4PD
UK
Tel +44 (0)20 7496 4000
BP America Inc.
501 Westlake Park Boulevard
Houston, Texas 77079
US
Tel +1 281 366 2000
Registered in England and Wales No. 102498.
Stock exchange symbol ‘BP.’
BP Annual Report and Form 20-F 2013
Strategic
report
An overview of the key
activities, events and results
in 2013, together with
commentary on BP’s
performance in the year and
our priorities as we move
forward.
2 BP at a glance
6 Chairman’s letter
8 Group chief executive’s letter
10 Our market outlook
12 Our business model
13 Our strategy
18 Our key performance indicators
20 Our approach to executive directors’ remuneration
22 Group performance
25 Upstream
31 Downstream
35 Rosneft
37 Other businesses and corporate
38 Gulf of Mexico oil spill
41 Corporate responsibility
41 Safety
44 Environment and society
47 Employees
49 Our management of risk
51 Risk factors
56 Liquidity and capital resources
1
BP Annual Report and Form 20-F 2013Strategic report
Finding
oil and gas
Developing and extracting
oil and gas
First, we acquire exploration rights,
then we search for hydrocarbons
beneath the earth’s surface.
Once we have found
hydrocarbons, we work to bring
them to the surface.
BP at a glance
BP delivers energy products
and services to people around
the world.
Through our two main operating segments,
Upstream and Downstream, we find, develop
and produce essential sources of energy,
turning them into products that people need.
We also buy and sell at each stage of the
hydrocarbon value chain.
In renewable energy, our activities are focused
on biofuels and wind.
We also have a 19.75% shareholding in Rosneft.
Business model
For more information on our business
model see page 12.
Our group key performance indicators (KPIs)
are shown on page 18. Some of the financial
KPIs are not recognized GAAP measures, but
are provided for investors because they are
closely tracked by management to evaluate
BP’s operating performance and to make
financial, strategic and operating decisions.
Group
BP p.l.c. is the parent company of
the BP group of companies. Our
worldwide headquarters is in London.
Upstream
Our Upstream segment manages exploration,
development and production activities through
global functions with specialist areas of
expertise.
See KPIs page 18.
See Upstream page 25.
$23.5bn
profit attributable to
BP shareholders
$21.1bn
operating cash
flowa
16.2%
gearing (net
debt ratio)b
3.2
million barrels of oil
equivalent per dayc
31
fewer reported
losses of primary
containmentd
a See footnote a on page 56.
b Net debt is not a recognized
GAAP measure, see
Financial statements –
Note 28.
c See footnote g on page 24.
d Compared with 2012.
2
Upstream proved reservese $16.7bn
14
replacement cost profit
before interest and tax
2.3
million barrels of oil
equivalent per day
43,000km2
new exploration access
3
Upstream major project start-ups
2
3
Liquidsf
1. Subsidiaries
2. Equity-accounted entities
Total
4,349
745
5,094
Natural gas
3. Subsidiaries
4. Equity-accounted entities
Total
5,894
434
6,328
e Million barrels of oil equivalent. Natural gas is converted to oil equivalent
at 5.8 billion cubic feet (bcf) = 1 million barrels. Excludes BP’s share of
Rosneft reserves. See Rosneft on page 36.
f Liquids comprise crude oil, condensate, natural gas liquids and bitumen.
BP Annual Report and Form 20-F 2013
All data provided on pages 2-5 is at or
for the year ended 31 December 2013.
Transporting and trading
oil and gas
Manufacturing
fuels and products
Marketing
fuels and products
We move hydrocarbons using pipelines,
ships, trucks and trains and we capture
value across the supply chain.
We refine, process and blend
hydrocarbons to make fuels, lubricants
and petrochemicals.
We supply our customers with fuel for
transportation, energy for heat and light, lubricants
to keep engines moving and the petrochemicals
required to make a variety of everyday items.
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Fuels
Lubricants
Petrochemicals
International oil and
gas markets
Investing
in renewable energy
We develop and invest in biofuels and operate a
wind business. BP’s lower-carbon businesses
are managed through our Alternative Energy
business.
Downstream Our Downstream segment operates
hydrocarbon value chains covering three
main businesses – fuels, lubricants and
petrochemicals.
Biofuels
See Downstream page 31.
Operating capital employedg
1
3
2
$2.9bn
1. Fuels
$42.3bn
2. Lubricants
$1.8bn
replacement cost profit
3. Petrochemicals
$5.4bn
before interest and tax
See Alternative Energy page 37.
1.8
7.4
million barrels of oil refined
per day
million tonnes of biofuels – total sugar
cane crush capacity per annum
Operating capital employedg
1
3
2
1. Fuels
2. Lubricants
3. Petrochemicals
$42.3bn
$1.8bn
$5.4bn
13.9
40%
million tonnes of petrochemicals
produced in the year
of our lubricants sales were
premium grades
1,590MW
net wind generation capacityh
g Operating capital employed is total assets (excluding goodwill) less total liabilities,
excluding finance debt and current and deferred taxation.
h Includes 32MW of capacity in the Netherlands, which is
managed by our Downstream segment.
3
Strategic reportBP Annual Report and Form 20-F 2013
BP around the world
BP has operations in around
80 countries.
The shaded areas indicate countries
where we have operations or interests.
Upstreama
Primarily (>75%) liquids.
Primarily (>75%) natural gas.
Liquids and natural gas.
Exploration site.
a Locations are categorized as liquids or natural gas based on
2013 production. Where production is yet to commence,
categorization is based on proved reserves. Exploration sites
have no significant proved reserves or production as at
31 December 2013.
Upstream see page 25.
Downstream
Refinery.
Petrochemicals site(s).
Downstream see page 31.
Alternative Energy
Operational assets.
Technology assets.
Alternative Energy see page 37.
BP group headcount by region
(including 14,100 service station staff)
7
16
5
4
3
2
1. Europe
2. US and Canada
3. Asia
4. South and Central
32,600
19,800
16,200
America
5. Middle East,
North Africa
6. Sub-Saharan
Africa
7. Russia
Total
6,900
5,700
2,400
300
83,900
4
Lubricants
Fuels
We manufacture and market lubricants
and related products and services directly
in about 45 countries and use approved
local distributors for other geographies.
We leverage brand, technology and
relationships, focusing our resources on
core and growing markets such as Brazil,
Russia, India and China.
Our fuels business is made up of regionally
based integrated fuels value chains, which
include refineries and fuels marketing
businesses together with global oil supply
and trading activities. We supply fuel and
related convenience services to consumers
at approximately 17,800 BP-branded
retail sites and have operations in almost
50 countries.
Gulf of Mexico
Alternative Energy
We have been exploring in the deepwater Gulf
of Mexico for more than 25 years and have
around 620 lease blocks, more than any other
company. We produce from more than 10 fields
including Thunder Horse and Atlantis – two of
the Gulf’s largest and deepest fields.
We operate three ethanol production
facilities in Brazil, have a joint venture
ethanol production facility in the UK and
operate a biofuels technology centre in
the US. We also have interests in 16 wind
farms in the US.
BP Annual Report and Form 20-F 2013
North Sea
Azerbaijan
Our activity in the North Sea region
encompasses the entire industry life cycle,
from access and exploration to production and
decommissioning. We operate more than 20
oil and gas fields, two major terminals and an
extensive network of pipelines.
We invest more in Azerbaijan than any other
foreign company, operating two production-
sharing agreements as well as holding other
exploration leases. The Caspian Sea is one
of the world’s major hydrocarbon provinces,
and the development of the region’s offshore
oil and gas fields and onshore pipelines has
made Azerbaijan a focal point of the global
energy market.
Rosneft
Rosneft is Russia’s largest oil company
and the world’s largest publicly traded oil
company in terms of hydrocarbon
production. BP’s 19.75% share of Rosneft’s
proved reserves on an SEC basis is 5 billion
barrels of oil and 9 trillion cubic feet of gas.
Rosneft’s downstream operations include
interests in 23 refineries (see page 35).
Angola
Petrochemicals
We have interests in nine offshore deep
and ultra deepwater blocks in Angola with a
total acreage of more than 32,600km2. Our
Plutão, Saturno, Vénus and Marte (PSVM)
offshore development began producing oil
in December 2012 and is one of the largest
subsea developments in the world.
We produce petrochemicals products
across our 15 manufacturing sites, and sell
our products to customers in more than
40 countries. Approximately 45% of our
capacity is in Asia, 30% in the US and 25%
in Europe.
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Strategic reportBP Annual Report and Form 20-F 2013
Chairman’s letter
The measures taken to secure
and reshape the group are
taking hold. BP is stronger and
safer as a result.
Carl-Henric Svanberg
Dear fellow shareholder,
In 2013 BP continued the programme of renewal we began following the crisis of 2010.
The measures taken to secure and reshape the group are taking hold. As this report
shows, BP is stronger and safer as a result.
Change within the group has taken place against the backdrop of a rapidly evolving world.
The energy landscape is developing at pace, for example, the growth of shale gas in the
US. But the long-term supply challenge has not gone away. More energy is required to
meet the needs and aspirations of a rising global population. The BP Energy Outlook
projects an average increase in energy demand of 1.5% per year through to 2035. That’s
like adding the needs of a country twice the size of the US over the next twenty years.
We are also seeing that society has ever higher expectations of business. This is reflected
in the increasing scrutiny placed on the commercial sector, particularly by politicians and
the media. Companies must work hard to maintain people’s trust and respect.
Shareholders’ expectations are shifting too, particularly in the extractive industries sector.
Some investors feel that international oil companies have spent too much for too little
return. A decade of mergers and acquisitions in our industry has generated little production
growth. Capital expenditure has increased but profit margins have been squeezed. Rightly,
shareholders expect better returns.
The board recognizes this changing world and the importance of our response. Throughout
2013 we gave close attention to strategy, project appraisal and capital discipline, working
with Bob Dudley and his team to ensure the group spends its money wisely. BP’s strategy
is rooted in three imperatives: clear priorities, a quality portfolio and distinctive capabilities.
23.40
20.85
17.40
Our first clear priority is to run safe and reliable operations. We must also make disciplined
financial choices, selecting the smart options that can help meet demand and generate
value. Furthermore, we must be competitive in how we execute our projects.
Our quality portfolio, which is at the core of our strategy, is the result of the choices we
make. It contains assets that enable us to play to our areas of greatest strength, from
exploration to high-value upstream projects – particularly deepwater operations, giant
fields and gas value chains – and high-quality downstream businesses.
To these assets and activities we apply our distinctive capabilities – the expertise of our
people, advanced technology and the ability to build the strong relationships required to
access resources and deliver complex projects.
219
198
168
84
In all of this, we are focused on value before volume. In other words we don’t simply chase
production for the sake of it, rather we choose projects where we can generate the most
value through our production.
We know we must be disciplined, sticking to clear limits on capital expenditure, and
balancing rewards for shareholders today with the long-term capital investment required
for tomorrow. Safety and strong governance must underpin everything we do.
10-year dividend history
UK (pence per ordinary share)
36.42
29.39
21.10 21.00
19.15
40
30
20
15.25
10
8.68
US (cents per ADS)
330 336
254
230
209
400
300
200
166
100
04
05
06
07
08
09
10
11
12
13
04
05
06
07
08
09
10
11
12
13
One ADS represents six 25 cent ordinary shares.
2013 was a busy and successful year for BP, with progress in our underlying operations.
Our growing confidence was reflected in the dividend increase announced in October
6
BP Annual Report and Form 20-F 2013 Board performance
For information about the board and its
committees see page 71.
Remuneration
For information about our approach to
executive directors’ remuneration see
page 20.
Top: Members of BP’s safety, ethics and
environment assurance committee (SEEAC)
visited Canada to see the oil sands operations at
the Sunrise project site and meet local
community leaders and staff.
Bottom: Members of SEEAC travelled to the
Gelsenkirchen refinery in Germany to speak with
apprentices and control room operators about risk
management and processes.
2013 – the third increase in two years. We also returned value to shareholders through the
$8-billion share repurchase programme announced in March 2013. Additional distributions
are planned as we make further divestments to reshape our portfolio. The milestones set
for 2014 will be an important measure of progress and your board is monitoring this
closely.
I am particularly pleased that in 2013 we completed our transaction with Rosneft, closing
one chapter in Russia and opening another. This is an important investment with the
potential to create substantial value for BP over the years to come.
2013 also saw the shocking attack at the In Amenas facility in Algeria. Our thoughts
remain with the families and friends of those who died. The response of management to
this tragedy was strong and the board acted positively and promptly.
We continue to address uncertainty in the US. In 2013, we once again met our
responsibilities to the region by paying legitimate claims arising from the 2010 accident
and oil spill in the Gulf of Mexico. And we met our responsibilities to shareholders by
challenging and resisting any attempt to take advantage of BP with claims that are not
legitimate. We will fight through the courts until matters are resolved properly, however
long that takes. In the meantime, the board is working to ensure that BP is not distracted
from growing the business and creating shareholder value.
Boards set the tone and values that shape performance and behaviour over the long term.
An effective board creates an enduring framework within which management can lead.
Having been through challenging times, the BP board has grown into a strong team with
experienced non-executives drawn from relevant industries. This year, more than ever,
they have been out to see BP’s operations for themselves, from India to Indiana. We
continue to be assisted on geopolitical matters by the international advisory board.
Our approach to governance has enabled us to focus on critical strategic issues, with our
board committees taking on the many oversight and compliance matters that require
attention.
Remuneration continues to be a board matter of particular importance to shareholders,
with executive pay policy now subject to a vote at the annual general meeting. BP has a
record of ensuring there are clear links between strategy, performance and remuneration.
This will continue.
I believe diversity helps to strengthen the effectiveness of a board. We plan succession
well ahead and are developing a pipeline of potential board candidates. We are committed
to progress and finding the right people for our board.
I would like to end by thanking you, our shareholders, for your continued support. I also
want to acknowledge the people who drive your company forward every working day.
From Bob Dudley and his management team to employees across the business; our
people are doing a great job of transforming BP. Their hard work has moved us forward,
with the promise of more to come.
Carl-Henric Svanberg
Chairman
6 March 2014
7
Strategic reportBP Annual Report and Form 20-F 2013
Group chief executive’s letter
We made new discoveries,
started up new operations,
strengthened our portfolio
and secured a new future
in Russia.
Bob Dudley
Dear fellow shareholder,
For BP, 2013 was a year of good progress in building a safer, stronger and better
performing company. We made new discoveries, started up new operations, strengthened
our portfolio and secured a new future in Russia. We also maintained our investment in the
US while standing up for what we believe to be right.
Within BP, sadly, 2013 will also be remembered for the terrorist attack in Algeria in
January, when four staff members and 36 colleagues from other companies were killed.
Those who died had many friends in BP and our thoughts remain with their loved ones,
and with those who survived that terrible ordeal. I was proud of the way people in BP
responded – with great compassion, but also with great fortitude.
This report contains a wealth of information on our performance. I would like to draw out
a few of the year’s highlights, all of which demonstrate how we are implementing our
strategy, with its emphasis on clear priorities, a quality portfolio and distinctive capabilities.
Clear priorities: safety, capital discipline, project execution
The first of our priorities is to run safe and reliable operations. In 2013 we made good
progress overall, but unfortunately we also suffered two driving-related fatalities as well as
the loss of the four employees murdered at In Amenas. Our thoughts are with those who
have been bereaved. We will implement the lessons learned.
In terms of general safety performance, however, we saw some encouraging progress.
The number of tier 1 process safety events – the most significant incidents – fell to 20
from 43 in 2012 and 74 in 2011. We are definitely heading in the right direction, but there
is always more to do and we remain vigilant.
We also saw improvements in measures that reflect the underlying health of our business.
For example, in upstream BP-operated plant efficiencya reached 88%, and refining
availability in downstream averaged 95.3% – the highest level for 10 years. These numbers
reinforce my view that safety and value have the same roots: systematic, disciplined
operations, undertaken by people who respect each other and work as one team.
In terms of capital discipline, in 2013 we invested $24.6 billionb, which kept us within our
$25-billion limit, and we expect to keep capital expenditure broadly the same in 2014. We
know we have to invest wisely so we maintain our shareholders’ trust.
Turning to project execution, we saw three upstream major projects start up in 2013 – in
the Gulf of Mexico, Angola and Australia. Three more followed closely in the first months
of 2014 – the Chirag oil project in Azerbaijan and the Mars B and Na Kika Phase 3 projects
in the Gulf of Mexico.
Quality portfolio
Beyond these start-ups, we extended our portfolio as a platform for growth in several
other ways.
For example, we grew our exploration position by participating in seven potentially
commercial discoveries, in Angola, Brazil, Egypt, India and the Gulf of Mexico. We also drilled
17 exploration wells, more than in the previous two years put together. BP has built up great
skills in finding oil and gas and we are seeing the results of investing in our explorers.
95.3%
2013 refining availability.
129%
Reserves replacement ratio, excluding the impact
of acquisitions and divestments.
See footnote b on page 14.
8
BP Annual Report and Form 20-F 2013 Our strategy
For more on our strategic priorities and
longer-term objectives see page 13.
And in the US lower 48 – which excludes Alaska and Hawaii – we intend to create a separate
BP business to manage our onshore oil and gas assets, which we believe will help to unlock
the significant value associated with our extensive resource position there.
Top: Bob Dudley and Iraq Oil Minister Abdul
Karim Al Luaibi (right) being shown the first meter
to be installed on one of the wells in Kirkuk. In
October BP signed an agreement with the
government of Iraq on providing technical
assistance relating to the Kirkuk oil field.
Bottom: Investors see how BP manages the risks
of deepwater drilling at a field trip in Houston.
They tested our well simulator which gives rig
operators a better understanding of both
prevention and response techniques.
Our reserves replacement ratio was 129% of production. When we include the net growth
in our Russian portfolio as a result of the change of our holdings, the reserves replacement
ratio on a combined basis was 199%.c
In the Downstream, we completed the commissioning of all major units for the Whiting
refinery. This landmark modernization programme, our fourth major project start-up in
2013, is turning what began as a 19th century plant into a truly 21st century one. It is now
able to compete strongly by processing a wide range of crudes, including heavy oil from
Canada.
More generally, our Downstream business has transformed its shape over the last five
years. In the US, we have sold two facilities and we now have three modern refineries
that are well configured and well connected to important markets. In lubricants, 40% of
revenue now comes from our premium brands. In petrochemicals, we are also focusing on
high-growth regions and new technologies.
Distinctive capabilities
New acetic acid and ethylene technologies announced by the petrochemical team in 2013
are among a series of innovations we have developed in support of our exploration,
production, refining and marketing activities. These include advanced seismic imaging
capacity – using one of the world’s largest civilian supercomputers – enhanced oil recovery
techniques and leading lubricant processes.
Our technologies are complemented by the capabilities of our people, which we continue
to deepen through training and development, and our experience in building and
maintaining relationships.
New future in Russia
Relationships have been vital in securing a new future for BP in Russia as a 19.75%
shareholder in Rosneft. Rosneft is implementing its strategy for growth across a promising
portfolio and paid us a dividend of $456 million in 2013. We look forward to exploring
opportunities for BP to work with Rosneft in the years ahead.
Making our case in the US
BP has continued to meet its commitment to environmental and economic restoration in
the Gulf of Mexico. We have also been swift to counter illegitimate claims and to argue for
a fair resolution to compensation matters. By the end of the year the total cumulative cost
to the company had reached $42.7 billion, the scale of that amount underlining once again
that BP is living up to its responsibilities in the region and to the US as a whole. The US
remains vitally important to today’s BP, with around 20,000 employees across the country
and we estimate that our economic activity supports a further 240,000 additional jobs.
Nearly 40% of our shares are held in the US, and we invest more there than in any other
country.
Looking ahead
We are a smaller but stronger company, having divested $38 billion of assets over three
years. In October we announced that we would divest around a further $10 billion of
assets before the end of 2015 – a decision that reflects our commitment to balancing
reinvestment with rewards for our shareholders. We expect to use the proceeds
predominantly for distributions to shareholders, with a bias to share buybacks.
Our unrelenting focus on capital discipline and systematic operating is increasing the free
cash flowd we have available. We are on track to meet our goal of generating more than
$30 billion of operating cash flow in 2014, an increase of more than 50% on 2011.e
I’m looking forward to 2014 with great confidence. I think you will see a re-energized and
refocused BP – a company that is set to become stronger and safer in every way, as we
fulfil our mission of delivering energy to customers and value to shareholders.
a See footnote a on page 25.
b Excludes acquisitions and Rosneft transaction.
c See page 247 for further information.
d See footnote c on page 56.
e See footnote b on page 56.
Bob Dudley
Group Chief Executive
6 March 2014
9
Strategic reportBP Annual Report and Form 20-F 2013
Our market outlook
We believe that a diverse mix of fuels and technologies will
be essential to meet the growing demand for energy and the
challenges facing our industry.
Population and economic growth are the main
drivers of global energy demand. The world’s
population is projected to increase by 1.7 billion
from 2012 to 2035, with real income likely to
more than double over the same period.
Therefore, the overall trend is likely to be one
of increased energy demand, even with energy
and climate policies and a shift towards less
energy-intense activities in fast-growing
economies. We expect demand for energy
to increase by as much as 41% between
2012 and 2035.
Challenges and opportunities
We seek energy sources that have the following
attributes:
Affordability – meeting growing demand
for secure and sustainable energy presents
an affordability challenge. Fossil fuels will
become increasingly difficult to access and
many lower-carbon resources will remain costly
to produce at scale.
Security – each country knowing where its
supplies will come from. More than 60% of the
world’s known reserves of natural gas are in just
five countries and at least 80% of global oil
reserves are located in nine countries, most of
which are distant from the hubs of energy
consumption. This represents a security
challenge in its own right.
Sustainability – avoiding an unacceptable
environmental and social impact that ultimately
negates the economic benefits. While energy
is available to meet growing demand, action
is needed to limit carbon dioxide (CO2) and
other greenhouse gases emitted through fossil
fuel use.
A diverse mix
We believe a diverse mix of fuels and
technologies can enhance national and global
energy security while supporting the transition
to a lower-carbon economy. These are reasons
why BP’s portfolio includes oil sands, shale gas,
deepwater oil and gas, and biofuels.
Oil and natural gas
Oil and natural gas are likely to play a significant
part in meeting demand for several decades.
We believe these energy sources will represent
about 54% of total energy consumption in 2035.
Even under the International Energy Agency’s
most ambitious climate policy scenario (the 450
scenario), oil and gas would still make up 47%
of the energy mix in 2035.a The 450 scenario
assumes governments adopt commitments to
limit the long-term concentration of greenhouse
gases in the atmosphere to 450 parts-per-million
of CO2 equivalent.
We expect oil to remain the dominant source for
transport fuels, accounting for as much as 87%
of demand in 2035.
Natural gas, in particular, is likely to play an
increasingly strategic role. Shale gas is expected
to contribute 47% of the growth in global natural
gas supplies between 2012 and 2035. The shale
gas revolution has already had a significant
impact on gas prices and demand in the US and
may encourage similar developments elsewhere
although the scale and speed of the roll out of
shale gas technology will vary between
countries. When used in place of coal for power,
natural gas can reduce CO2 emissions by half.
a From World Energy Outlook 2013. © OECD/International
Energy Agency 2013, page 573.
Our third PTA plant in Zhuhai, China, is planned to
begin production in late 2014. It is expected to
bring total capacity at the site to more than 2.7
million tonnes per year.
Thunder Horse in the Gulf of Mexico is one of the
largest integrated offshore drilling and production
platforms in the world.
2013 pricing
See Upstream on page 26 and
Downstream on page 32.
10
BP Annual Report and Form 20-F 2013
S
t
r
a
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e
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i
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r
e
p
o
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New sources of hydrocarbons are more
difficult to reach, extract and process. BP and
others in our industry are working to improve
techniques for maximizing recovery from
existing and currently inaccessible or
undeveloped fields. In many cases, the
extraction of these resources might be more
energy intensive, which means operating costs
and greenhouse gas emissions from operations
may also increase.
Renewable energy
Renewables will play an increasingly important
role in addressing the challenges of energy
security and climate change over the long term.
Renewables are already the fastest-growing
energy source, but they are starting from a
low base.
By 2035, we estimate renewable energy,
excluding large-scale hydro electricity, is likely to
meet around 7% of total global energy demand.
Energy efficiency and innovation
Greater efficiency addresses several aspects of
the energy challenge. It helps with affordability
– because less energy is needed. It helps with
security – because it reduces dependence on
imports. And it helps with sustainability –
because it reduces emissions.
Innovation can play a key role in improving
technology design, process and use of materials,
bringing down cost and increasing efficiency. In
transport, for example, we believe that efficient
technologies and combustion engines that use
biofuels could offer the most cost-effective
pathway to a secure, lower-carbon future.
Policy, prices and access
If the world’s growing demand for energy is to
be met in a sustainable way, we believe that
governments must set a stable and enduring
framework for the private sector to invest and
for consumers to choose wisely. This includes
secure access for exploration and development
of energy resources, mutual benefits for
resource owners and development partners, and
an appropriate legal and regulatory environment.
We believe open and competitive markets are
the most effective way to encourage companies
to find, produce and distribute diverse forms of
energy sustainably. The US experience with
shale gas shows how an open and competitive
environment can drive technological innovation
and unlock resources.
We also believe that putting a price on carbon
– one that treats all carbon equally, whether it
comes out of a smokestack or a car exhaust –
will make energy efficiency and conservation
more attractive to businesses and individuals
and lower-carbon energy sources more cost
competitive. A global carbon price should
be the long-term goal, but regional and national
approaches are a good first step, provided
temporary financial relief is given to sectors
that are exposed to international competition.
Beyond 2035
We expect that growing population and per
capita incomes will continue to drive growing
demand for energy. These dynamics will be
shaped by future technology developments,
changes in tastes, and future policy choices –
all of which are inherently uncertain. Concerns
about energy security, affordability and
environmental impacts are all likely to be
important considerations. These factors may
accelerate the trend towards more diverse
sources of energy supply, a lower average
carbon footprint, increased efficiency and
demand management.
Strategy
Find out how BP can help meet energy
demand for years to come on page 13.
Air BP is one of the world’s largest aviation fuels
suppliers, marketing aviation fuels and specialist
products in more than 45 countries. It sells over
seven billion gallons of fuel per year.
BP Annual Report and Form 20-F 2013
11
BP Energy Outlook contains our projections of
future energy trends and factors that could affect
them, based on our views of likely economic and
population growth and developments in policy
and technology. Available in PDF, Excel and video
format.
See bp.com/energyoutlook.
Energy consumption by region
(billion tonnes of oil equivalent)
Other
India
China
OECD
18
16
14
12
10
8
6
4
2
1990
2000
2010
2020
2035
Source: BP Energy Outlook 2035.
Energy consumption by fuel
(billion tonnes of oil equivalent)
Renewables*
Hydro
Nuclear
Coal
Gas
Oil
18
16
14
12
10
8
6
4
2
1990
*Includes biofuels.
Source: BP Energy Outlook 2035.
2000
2010
2020
2035
Our business model
We aim to create shareholder value across the
hydrocarbon value chain.
Toledo refinery in Ohio has been in constant
operation since 1919. The facility has the capacity
to process up to 160,000 barrels of crude per day.
The redevelopment project at Valhall was
one of BP’s most complex field expansion
developments and gives the field a further
40-year design life.
A rising global population and increasing levels of
prosperity are set to create growing demand for
energy for years to come. We can help to meet
that demand by producing oil and gas safely and
reliably.
We believe that the best way to achieve
sustainable success as a group is to act in the
long-term interests of our shareholders, our
partners and society. We aim to create value for
our investors and benefits for the communities
and societies in which we operate, with the
responsible supply of energy playing a vital role
in economic development.
Every stage of the hydrocarbon value chain
offers opportunities for us to create value – both
through the successful execution of activities
that are core to our industry, and through the
application of our own distinctive strengths and
capabilities in performing those activities. In
renewable energy our focus is on integrating
biofuels into the hydrocarbon value chain, and
on wind operations in the US.
Our approach spans everything from exploration
to marketing. Integration across the group allows
us to share functional excellence more efficiently
across areas such as safety and operational risk,
environmental and social practices, procurement,
technology and treasury management.
A relentless focus on safety remains the top
priority for everyone at BP. Rigorous
management of risk helps to protect the people
at the front line, the places in which we operate
and the value we create. We understand that
operating in politically complex regions and
technically demanding geographies requires
particular sensitivity to local environments.
Our businesses
For more information on our upstream,
downstream and alternative energy
businesses, see pages 25, 31 and 37
respectively.
Our business model
Finding oil
and gas
First, we acquire the rights to
explore for oil and gas. Through
our exploration activities we are
able to renew our portfolio,
discover new resources and
replenish our development
options.
12
Developing and
extracting
Transporting
and trading
Manufacturing and
marketing
When we find hydrocarbon resources,
we create value by seeking to
progress them into proved reserves
or by divesting if they do not fit with
our strategy. If we believe developing
and producing the reserves will be
advantageous for BP, we produce
the oil and gas, then sell it to the
market or distribute it to our
downstream facilities.
We move oil and gas through
pipelines and by ship, truck and train.
Using our trading and supply skills
and knowledge, we buy and sell at
each stage in the value chain. Our
presence across major trading hubs
gives us a good understanding of
regional and international markets
and allows us to create value
through entrepreneurial trading.
Using our technology and expertise,
we manufacture fuels and products,
creating value by seeking to operate
a high-quality portfolio of well-
located assets safely, reliably and
efficiently. We market our products
to consumers and other end-users
and add value through the strength
of our brands.
Our illustrated business model see page 2.
BP Annual Report and Form 20-F 2013
Our strategy
Our goal is to be a focused oil and gas company that
delivers value over volume.
Financial discipline
$
i n g c a s h fl o w
O p e r a t
N e t i n v e s t m e n t
Free cash flow
(Not to scale)
Time
This chart illustrates the expected relationship
between operating cash flowa, net investmentb
(includes capital expenditure offset by any
divestments) and free cash flowc. It is not a
projection of future performance.
• Operating cash flow – we aim to continue
growing our operating cash flow, with an
expected delivery of $30 billion to $31
billion in 2014.d
• Capital expenditure – we expect our
annual capital expendituree to remain
between $24 billion and $25 billion in 2014
and to be in the range of $24 billion to
$26 billion in the years 2015 to 2018.
• Divestments – we intend to divest
$10 billion of assets before the end of 2015.
• Free cash flow – delivering sustainable free
cash flow underpins our ability to deliver
increasing shareholder returns.
a See footnote a on page 56.
b Equivalent to net cash used in investing activities.
c See footnote c on page 56.
d See footnote h on page 24.
e Excludes acquisitions and asset exchanges.
f Unit cash margin is net cash provided by operating activities by
the relevant projects in our Upstream segment, divided by the
total number of barrels of oil equivalent produced for the relevant
projects.
g Assuming a constant oil price of $100 per barrel.
h See footnote b on page 56.
i See footnote d on page 56.
We are pursuing our strategy by setting clear
priorities, actively managing a quality portfolio
and employing our distinctive capabilities. Our
financial objective is to create shareholder value
by generating sustainable free cash flow
(operating cash flow less net investment). This
disciplined approach enables us to invest for the
future while aiming to increase distributions to
our investors.
Clear priorities
First, we aim to run safe, reliable and compliant
operations – leading to better operational
efficiency and safety performance. We also aim
to achieve competitive project execution, which
is about delivering projects efficiently so they are
on time and on budget. And we aim to make
disciplined financial choices, so we can achieve
continued growth in operating cash from our
underlying businesses and disciplined allocation
of capital.
Quality portfolio
We undertake active portfolio management to
concentrate on areas where we can play to our
strengths. This means we continue to grow our
exploration position, reloading our upstream
pipeline. We focus on high-value upstream
assets in deepwater, giant fields and selected
gas value chains. And, with our downstream
businesses, we plan to leverage our newly
upgraded assets, customer relationships and
technology to grow free cash flow.
Our portfolio of projects and operations is
focused where we can generate the most value,
and not necessarily the most volume, through
our production.
Distinctive capabilities
Our ability to deliver against our priorities and
build the right portfolio depends on our
distinctive capabilities. We apply advanced
technology across the hydrocarbon value chain,
from finding resources to developing energy-
efficient and high-performance products for
customers. We rely on our strong relationships
– with governments, partners, civil society and
others – to enable our operations in around 80
countries across the globe. And, the proven
expertise of our employees comes to the fore
in a wide range of disciplines.
Our strategy in action
See page 14 for more information
on how we are going to measure our
progress.
10-point plan 2011-2014
In 2011 we laid out a 10-point plan designed to stabilize the company and restore trust and value in
response to the tragic Deepwater Horizon accident. Our priority was to make BP a safer, more
risk-aware business. The plan included a series of milestones by which our progress could be
tracked, from 2012 through to 2014. Information on our progress during 2013 can be found in Group
performance on page 22.
1
2
3
4
5
A relentless focus on safety and managing
risk through the systematic application of
global standards.
We will play to our strengths in exploration,
deep water, giant fields and gas value chains.
Stronger and more focused with an asset
base that is high graded and higher
performing.
Simpler and more standardized with fewer
assets and operations in fewer countries;
more streamlined internal reward and
performance management processes.
Improved transparency through reporting
TNK-BP as a separate segment and breaking
out the numbers for the three downstream
businesses.
6
7
8
9
Active portfolio management to continue
by completing $38 billion of disposals over
the four years to the end of 2013, in order
to focus on our strengths.
We expect to bring new upstream projects
onstream with unit operating cash marginsf
around double the 2011 average by 2014.g
We are aiming to generate an increase
of around 50% in net cash provided by
operating activities by 2014 compared
with 2011.h
We intend to use half our incremental
operating cash for reinvestment, half for
other purposes.
10 Strong balance sheet with intention to
target our level of gearingi in the lower
half of the 10-20% range over time.
13
Strategic reportBP Annual Report and Form 20-F 2013
Our strategy in action
Delivering energy
to the world
Safe, reliable and
compliant operations
Clear priorities
Safe, reliable and
compliant operations
Disciplined financial
choices
Competitive
project
execution
Disciplined
financial
choices
Competitive project
execution
Grow our
exploration
position
Focus on
high-value
upstream assets
Quality portfolio
Build high-quality
downstream businesses
Grow our
exploration
position
Focus on high-value
upstream assets
Build high-quality
downstream
businesses
Advanced
technology
Distinctive capabilities
Proven
expertise
Strong
relationships
Our ability to deliver
against our priorities
and build the right
portfolio depends on our
distinctive capabilities.
See page 16.
a See footnote d on page 56.
b On a combined basis of subsidiaries and equity-
accounted entities, excluding the impact of acquisitions
and disposals. Includes BP’s share of TNK-BP’s
production and reserves additions from 1 January 2013
to 20 March 2013, and BP’s share of Rosneft production
and reserves additions from 21 March 2013 to
31 December 2013.
c Combined production of subsidiaries and equity-
accounted entities.
14
BP Annual Report and Form 20-F 2013
How we deliver
Our KPIs
Strategy in action in 2013
S
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We prioritize the safety and reliability of our
operations to protect the welfare of our
workforce and the environment. This also helps
preserve value and secure our right to operate
around the world.
Recordable injury
frequency, loss of primary
containment, greenhouse
gas emissions, tier 1
process safety events.
We rigorously screen our investments and we work
to keep our annual capital expenditure within a set
range. Ongoing management of our portfolio helps
ensure focus on more value-driven propositions.
We balance funds between shareholder
distributions and investment for the future.
Operating cash flow,
gearinga, total shareholder
return, replacement
cost profit (loss) per
ordinary share.
We seek efficient ways to deliver projects on
time and on budget, from planning through to
day-to-day operations. Our wide-ranging project
experience makes us a valued partner and
enhances our ability to compete.
Major project delivery.
We target basins and prospects with the
greatest potential to create value, using our
leading subsurface capabilities. This allows
us to build a strong pipeline of future
growth opportunities.
We are strengthening our portfolio of high
return and longer life assets – across deep
water, giant fields and gas value chains – to
provide BP with momentum for decades
to come.
We benefit from our high-performing fuels,
lubricants, petrochemicals and biofuels
businesses. Through premium products,
powerful brands and supply and trading,
Downstream provides strong cash
generation for the group.
Reserves
replacement ratio.b
Production.c
Refining availability.
Creating shareholder value by generating
sustainable free cash flow
A commitment to
safe operations
Toledo refinery sets
a safety record.
See page 42.
31
fewer reported losses
of primary containment
than 2012.
Maximizing value
at Mad Dog
Changing plans to make
the best financial choices.
$21.1bn
operating cash flow.
See page 29.
Increasing oil production
in Azerbaijan
Local construction of BP’s
heaviest platform in the
Caspian Sea.
See page 48.
4
major project start-ups
in Upstream and
Downstream.
Discovering gas in India
Two significant discoveries
with Reliance Industries.
See page 30.
129%
reserves
replacement ratio.
Preparing for Shah Deniz
Stage 2
Largest gas sales contracts
in Azerbaijan’s history.
See page 27.
3.2
million barrels of oil
equivalent per day.
Creating our North American
advantaged refinery
Modernization project
improves utilization and
margin capture at Whiting.
See page 33.
95.3%
refining availability.
Advanced technology
We develop and deploy technologies
we expect to make the greatest impact on
our businesses – from enhancing the safety
and reliability of our operations to creating
competitive advantage in energy discovery,
recovery, efficiency and products.
Strong relationships
We form enduring partnerships in the
countries in which we operate, building strong
relationships with governments, customers,
partners such as Rosneft, suppliers and
communities to create mutual advantage.
Co-operation helps unlock resources found in
challenging locations and transforms them into
products for our customers.
Proven expertise
We attract and develop the talented people
required to drive our business forward.
They apply their diverse skills and expertise
to deliver complex projects across all areas
of our business.
BP Annual Report and Form 20-F 2013
15
Our distinctive capabilities
Advanced technology
We use technology to find and produce more
hydrocarbons, improve our processes for
converting raw materials and develop lower-
carbon products.
The development of technology from research
and development through to wide-scale
deployment can take several years. For example,
to reach the next generation of deepwater oil
reserves, where rock pressures can reach 20,000
pounds per square inch, we are developing new
subsea technologies through our Project 20K.
Technology programmes in our upstream
business include advanced seismic imaging to
help us find more oil and gas and enhanced oil
recovery to get more from existing fields. New
techniques are making recovery of
unconventional oil and gas, like shale,
economically viable.
See bp.com/technology.
We focus our downstream technology
programmes on the safety, integrity and
performance of our refineries and petrochemical
plants and on creating high quality, energy efficient,
cleaner fuels, lubricants and petrochemicals.
BP employs more than 2,000 scientists and
technologists.
Our long-term research programmes with
universities and research institutions around the
world are exploring areas from reservoir fluid
flow to energy biosciences. We have a strategic
approach to university relationships across our
portfolio for the purposes of research,
recruitment, policy insights and education.
In 2013 we invested $707 million in research and
development (2012 $674 million). See Financial
statements – Note 8.
1
2 Seismic imaging
We use our imaging expertise to increase the
productivity and quality of the data we capture
on land and offshore. With 80% of future
offshore oil and gas reserves thought to be
under salt canopies up to 7 kilometres high, our
new supercomputer in Houston helps to reduce
the completion times for imaging jobs from
several months to a matter of days.
1
3
2
4
4 Enhanced oil recovery (EOR)
Our LoSal EOR technology can help develop
previously unexploited resources from existing
oil fields. LoSal uses water with a low salt
content to release more molecules of oil from
the sandstone rock where they are held.
The Pangbourne technology centre is home to
chemists and liquid engineers dedicated to
providing products and services for Castrol’s
customers.
Proven expertise
Our employees enable BP to deliver our strategy
and meet our commitments to investors, partners
and the wider world.
Our people are talented in a wide range of disciplines,
from geoscience, mechanical engineering and
research technology to government affairs, trading,
marketing, legal and others. And our approach to
professional development programmes and training
helps build individual capabilities, reducing a potential
skills gap. This is vital in a world where oil and gas
companies face an increasing challenge to find and
retain skilled and experienced people.
We aim to achieve a balance between building
internal expertise and recruiting external
professionals and graduates. We have a strong,
experienced leadership team and a pipeline of
talent for the future.
16
3 Production optimization
Our Field of the Future technologies provide
real-time information to help manage operational
risk, improve plant equipment reliability and
optimize production. We use these technologies
to monitor more than 600 wells.
5 Shipping efficiency
Our ‘virtual arrival’ system can reduce fuel
consumption and emissions by allowing vessels,
ports and other parties to work together and
agree an optimum arrival time for each vessel.
Graduate intake
We hired 814 graduates,
including 44% recruited
from outside the UK
and US.
Internal promotion
We promoted 4,979
employees including
645 group and senior
level leaders.
Group leaders
We have more than 500
group leaders with an
average of 20 years’
experience.
Developing the talent pipeline
LinkedIn ranked BP thirteenth
most sought after company
to work for in the world (see
linkedin.com/indemand).
External hires
We hired 8,854 people
including 211 group and
senior level leaders.
Employees
See page 47.
BP Annual Report and Form 20-F 2013
5
6
7
8
9
10
6 Improved conversion
Our Veba Combi-Cracking technology converts
a wide variety of raw materials, ranging from
crude oil residue to mixtures of coal and oil, into
fuels. Using this technology we can convert
95% or more of our hydrocarbon resources to
marketable products.
8 Fuels and lubricants
We focus on providing energy-efficient and
high-performance products to customers.
Castrol EDGE, which is underpinned by our
proprietary Fluid Strength Technology, reduces
contact between engine surfaces to improve
performance and reduce wear from friction.
10 Biofuels
Conversion technology allows us to
produce cellulosic ethanol using alternative
raw materials such as agricultural waste
and fast-growing energy grasses. At our
biofuels technology centre in San Diego
around 120 scientists are researching and
advancing new biofuels technologies.
7 Corrosion prevention
Wireless Permasense® systems, developed in
collaboration with Imperial College, London, are
used across all our refineries to monitor the
integrity of critical oil and gas assets.
9 Petrochemicals
Our SaaBre technology converts synthesis gas
(carbon monoxide and hydrogen derived from
hydrocarbons) into acetic acid. The process
avoids the need to purify carbon monoxide or
purchase methanol, reducing manufacturing
costs and environmental impacts.
Strong relationships
Our relationships are crucial to the success
of our business. We work closely with
governments, national oil companies and other
resource holders. By acting responsibly and
meeting our obligations we build long-lasting
relationships.
From experience we know that trust can be lost,
so we place enormous importance on meeting
people’s expectations. We work in partnership
on big and complex projects with everyone from
other oil companies through to suppliers and
contractors. Our activity creates value that
benefits governments, customers, local
communities and other partners.
Internally we put together collaborative teams
of people with the skills and experience
needed to address complex issues, work
effectively with our partners and help
create shared value.
Universities
and research
institutions
National
and international
oil companies
Banks and
providers of
finance
Intern
l r e lation
s
a
h
i
p
s
Governments
and
regulators
BP
Industry
bodies
Customers
Communities
Suppliers,
partners and
contractors
17
Strategic reportBP Annual Report and Form 20-F 2013 Our key performance indicators
We assess the group’s performance
according to a wide range of
measures and indicators. Our key
performance indicators (KPIs) help
the board and executive
management measure performance
against our strategic priorities and
business plans. We keep these
metrics under periodic review and
test their relevance to our strategy
regularly. We believe non-financial
measures – such as safety and an
engaged and diverse workforce –
have a useful role to play as leading
indicators of future performance.
Changes to KPIs
This year, we introduced two new
KPIs: tier 1 process safety events
and major project delivery. These
demonstrate two of our strategic
objectives and are used as
measures for executive
remuneration.
We have removed the number of
oil spills as a group KPI as this is
reflected within the loss of primary
containment and tier 1 process
safety events KPIs. We continue to
report on oil spills, see Safety on
page 41.
Remuneration
To help align the focus of our board
and executive management with the
interests of our shareholders, certain
measures are reflected in the
variable elements of executive
remuneration.
Overall annual bonuses, deferred
bonuses and performance shares are
all based on performance against
measures and targets linked directly
to strategy and KPIs. For details of
our remuneration policy see page 96.
KPIs used to measure progress
against our strategy.
KPIs used to determine 2013
and 2014 remuneration.
Not all financial KPIs are
recognized GAAP measures, but
are provided for investors
because they are closely tracked
by management to evaluate BP’s
operating performance and to
make financial, strategic and
operating decisions.
18
Replacement cost profit (loss)
per ordinary share (cents)
Operating cash flow ($ billion)
Gearing (net debt ratio) (%)
160
120
80
40
0
123.83
125.08
73.34
60.05
(28.01)
50
40
30
20
10
27.7
13.6
22.2
20.5
21.1
25
20
15
10
5
20.4
21.2
20.4
18.7
16.2
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
Replacement cost profit (loss) is a useful
measure for investors because it is a
profitability measure BP management
use to assess performance and allocate
resources.
It reflects the replacement cost of
supplies and is calculated by removing
inventory holding gains and losses and
their associated tax effect from profit.
This is a non-GAAP measure for the
group. The IFRS equivalent can be
found on page 236.
2013 performance The increase in
replacement cost profit per ordinary
share for the year compared with 2012
reflected the gain on disposal of our
interest in TNK-BP.
Operating cash flow is net cash flow
provided by operating activities, from
the group cash flow statement.
Operating activities are the principal
revenue-generating activities of the
group and other activities that are not
investing or financing activities.
2013 performance Higher operating
cash flow in 2013 reflected a lower
cash outflow relating to the Gulf of
Mexico oil spill, partly offset by higher
cash outflows as a result of working
capital build.
Our gearing (net debt ratio) shows
investors how significant net debt is
relative to equity from shareholders in
funding BP’s operations.
We aim to keep our gearing within the
10-20% range to give us the flexibility to
deal with an uncertain environment.
Gearing is calculated by dividing net debt
by total equity plus net debt. Net debt is
equal to gross finance debt, plus
associated derivative financial
instruments, less cash and cash
equivalents. Net debt and net debt ratio
are non-GAAP measures. See Financial
statements – Note 28 for the nearest
equivalent measure on an IFRS basis and
for further information.
2013 performance Gearing at the end of
2013 was 16.2%, down 2.5% on 2012
and within our target band of 10-20%.
Refining availability (%)
Reported recordable injury
frequencya
Loss of primary containmenta
98
96
94
92
90
95.0
94.8
94.8
95.3
93.6
1.00
0.75
0.50
0.25
Employees
Contractors
4
8
.
0
3
4
.
0
3
2
.
0
5
2
.
0
3
4
.
0
1
4
.
0
6
2
.
0
1
3
.
0
6
3
.
5 0
2
.
0
875
700
525
350
175
537
418
361
292
261
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
Refining availability represents Solomon
Associates’ operational availability. The
measure shows the percentage of the
year that a unit is available for
processing after deducting the time
spent on turnaround activity and all
mechanical, process and regulatory
maintenance downtime.
Refining availability is an important
indicator of the operational performance
of our Downstream businesses.
2013 performance Refining availability
increased by 0.5% from 2012 to 95.3%
reflecting strong operations around our
global refining portfolio.
Reported recordable injury frequency
(RIF) measures the number of reported
work-related employee and contractor
incidents that result in a fatality or injury
(apart from minor first aid cases) per
200,000 hours worked.
The measure gives an indication of the
personal safety of our workforce.
2013 performance Our workforce RIF,
which includes employees and
contractors combined, was 0.31,
compared with 0.35 in 2012 and 0.36 in
2011. These successive reductions are
encouraging and we continue pursuing
improvement in personal safety.
Loss of primary containment (LOPC) is
the number of unplanned or
uncontrolled releases of oil, gas or other
hazardous materials from a tank, vessel,
pipe, railcar or other equipment used for
containment or transfer.
By tracking these losses we can monitor
the safety and efficiency of our
operations as well as our progress in
making improvements.
2013 performance Our reported LOPC
shows 31 fewer reported incidents in
2013 than in 2012, with divestments
accounting for a significant part of the
reduction. We remain committed to
using our operating management system
to further improve our operations.
BP Annual Report and Form 20-F 2013 Total shareholder return (%)
Reserves replacement ratio (%)
Major project delivery
Production (mboe/d)
ADS basis
Ordinary share basis
0
.
3
3
6
.
7
2
60
40
20
0
-20
)
1
.
4
2
(
)
4
.
1
2
(
5
.
2
0
.
3
5
.
4
6
.
2
7
.
4
1
0
.
4
1
129
106
103
140
120
100
80
60
129
10
8
77
8
6
4
2
5
4
3
2
3,998
3,822
4,250
4,000
3,750
3,500
3,250
3,454
3,331
3,230
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
Total shareholder return (TSR)
represents the change in value of a BP
shareholding over a calendar year. It
assumes that dividends are re-invested
to purchase additional shares at the
closing price on the ex-dividend date.
We are committed to maintaining a
progressive and sustainable dividend
policy.
2013 performance TSR grew as a result
of increases in both the BP share price
and in the dividend, with the
improvement for ordinary shares slightly
offset by exchange rate effects.
Proved reserves replacement ratio is the
extent to which the year’s production has
been replaced by proved reserves added
to our reserve base.
Major projects are defined as large-scale
projects with a high degree of
complexity and a BP net investment of
at least $250 million.
The ratio is expressed in oil-equivalent
terms and includes changes resulting from
discoveries, improved recovery and
extensions and revisions to previous
estimates, but excludes changes resulting
from acquisitions and disposals. The ratio
reflects both subsidiaries and equity-
accounted entities.
The measure helps to demonstrate our
success in accessing, exploring and
extracting resources.
2013 performance The increase in our
reserves replacement ratio included the
impact of final investment decisions on
two significant upstream projects in Oman
and Azerbaijan.
We monitor the progress of our major
projects to gauge whether we are
delivering our core pipeline of activity.
Projects take many years to complete,
requiring differing amounts of resource,
so a smooth or increasing trend should
not be anticipated.
2013 performance In total we delivered
four major projects. Three started up in
Upstream – Atlantis North expansion
Phase 1 in the Gulf of Mexico; Angola
LNG; and North Rankin Phase 2 in
Australia, and one in Downstream –
the Whiting refinery modernization
project.
We report the volume of crude oil,
condensate, natural gas liquids (NGLs)
and natural gas produced by subsidiaries
and equity-accounted entities. These are
converted to barrels of oil equivalent
(boe) at 1 barrel of NGL = 1boe and
5,800 standard cubic feet of natural gas
= 1boe.
2013 performance BP’s total reported
production including our Upstream
segment, and our share of TNK-BP
(from 1 January to 20 March) and
Rosneft (from 21 March to 31
December), was 3% lower than in 2012.
This was mainly due to the effect of
divestments in Upstream.
Tier 1 process safety eventsa
Greenhouse gas emissions
(million tonnes of CO2 equivalent)
Group priorities engagementc (%)
Diversity and inclusionc d (%)
100
80
60
40
20
2009
Data not
collected
74
74
100
80
60
40
20
43
20
65.0
64.9
61.8
59.8
49.2
100
80
60
40
20
Data not
collected
67
71
72
Women
Non UK/US
1
2
9
1
9
1
4
4
1
1
4
1
5
1
2
2
0
2
8
1
7
1
30
25
20
15
10
5
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
2009
2010
2011
2012
2013
We report tier 1 process safety events
(PSE), which are the losses of primary
containment of greatest consequence
– causing harm to a member of the
workforce, costly damage to equipment
or exceeding defined quantities.
2013 performance Our reduction in
reported tier 1 PSEs is supported
by our efforts to drive improvement in
process safety. Divestments also
account for part of the reduction. We are
aware there is always more to do to
improve.
a This represents reported incidents occurring
within BP’s operational HSSE reporting
boundary. That boundary includes BP’s own
operated facilities and certain other locations
or situations.
We report greenhouse gas (GHG)
emissions material to our business on a
carbon dioxide-equivalent basis. This
includes CO2 and methane for direct
emissions.b Our GHG reporting
encompasses all BP’s consolidated
entities as well as our share of
equity-accounted entities other than
BP’s share of TNK-BP and Rosneft.
Rosneft’s emissions data can be found
on its website.
2013 performance Our total greenhouse
gas emissions decreased by 18%,
primarily due to the divestment of our
Texas City and Carson refineries.
We track how engaged our employees
are with our strategic priorities for
building long-term value. The measure is
derived from answers to 12 questions
about BP as a company and how it is
managed in terms of leadership
and standards.
2013 performance We saw continued
improvement in 2013, and there was
an increase in understanding of our
operating management system, an area
of focus identified the previous year.
While the survey showed an increase in
employee confidence in BP’s leadership,
work is needed to further strengthen
this.
Each year we report the percentage of
women and individuals from countries
other than the UK and US among BP’s
group leaders.
This means we can track progress in
building a diverse and well-balanced
leadership team, helping to create a
sustainable pipeline of diverse talent for
the future.
2013 performance We have increased
the percentage of female leaders again
this year and have extended our focus on
diversity and inclusion beyond the board
and group leaders to include other levels
of management.
b For indirect emissions data see page 45.
c Relates to BP employees.
d Minor amendments have been made to 2012.
19
Strategic reportBP Annual Report and Form 20-F 2013
Our approach to executive
directors’ remuneration
Remuneration is directly linked to strategy and performance, with
particular emphasis on matching rewards to results over the long term.
A simple approach
Total remuneration is determined by a relatively simple approach
to attract and retain high calibre executives. The largest components
are share based and vest over a number of years – further aligning
executives’ interests with those of our shareholders.
Directors’ remuneration report
See bp.com/remuneration
and page 81.
Salary
Annual
bonus
Deferred
bonus
Performance
shares
Reflects scale
and dynamics of
the business.
Variable level
dependent on
short-term
performance.
Reinforces the long-term nature
of the business and the importance
of sustainability, and links more
total remuneration to equity.
Links the largest portion of remuneration to
long-term performance, with the level awarded
varying according to performance based on
measures directly linked to strategic priorities.
Pension and
benefits
Recognizes
competitive practice
in home country.
Underpinned by six key principles
The remuneration policy for executive directors and
the decisions of the remuneration committee of the
board are guided by six key principles:
1 Linked to strategy
A substantial portion of executive remuneration
is linked to success in implementing the
company’s strategy.
Strategic priorities and group key performance
indicators (KPIs) provide key metrics for the
performance shares and deferred bonus, and are
focused through the annual plan to provide the
measures for annual bonus.
Strategy
See page 13.
KPIs
See page 18.
Group KPIs used as performance
measures
Operating cash flow
Total shareholder return
Reserves replacement ratio
Major project delivery
Recordable injury frequency
Loss of primary containment
Tier 1 process safety events
Underlying replacement cost profit
2 Performance related
The major part of total remuneration varies with
performance, with the largest elements share
based, further aligning interests with
shareholders.
High pay requires high performance. Achieving
the maximum pay requires sustained high
performance over several years.
a n c e
u stain e d p erfo r m
S
y
a
P
20
Min
Target
Performance
Max
BP Annual Report and Form 20-F 2013
3 Long-term based
The structure of pay is designed to reflect the
long-term nature of BP’s business and the
significance of safety and environmental risks.
The largest components of total remuneration
are share based and vest over the longest
period. The deferred bonus plan requires
sustained safety and environmental performance
over three years. The matched shares that vest
under the plan have an additional three-year
retention period, resulting in a six-year time
frame. Similarly, performance shares have a
six-year time frame – a three-year performance
period followed by an additional three-year
retention period for those shares that vest.
4 Informed judgement
5 Shareholder engagement
6 Fair treatment
1 – 3 years
Performance period
4 – 6 years
Retention period
Deferred
bonus
Performance
shares
Shares vest based on performance
Matched shares released
Shares vest based on performance
Vested shares released
There are quantitative and qualitative
assessments of performance with the
remuneration committee making informed
judgements within a framework approved by
shareholders.
The committee has a preference for quantifiable
targets that can be factually measured and
objectively assessed according to well
understood principles and definitions. It seeks
the views of other relevant committees when
arriving at conclusions. It is not constrained
when conditions change requiring different
perspectives or when unanticipated events,
both good and bad, occur.
The remuneration committee actively seeks
to understand shareholder preferences and be
transparent in explaining its policy and practice.
During 2013 the remuneration committee
chairman met personally with shareholders
representing nearly 15% of total outstanding
shares. A number of adjustments to policy
were made in response to the feedback
received (see page 82).
Total overall pay takes account of both the
external market and company conditions to
achieve a balanced, ‘fair’ outcome.
The committee attempts to balance
sometimes conflicting perspectives to arrive
at total pay results that not only reflect
performance relative to strategy, but also are
deemed fair by external stakeholders and
employees, as well as the executive team.
There are no perfect
measures. Conditions
change. Events happen.
Judgement is vital.
Antony Burgmans
94%
of votes cast were in favour of the
2012 Directors’ remuneration
report.
Consistent
internally
Competitive
externally
Fair
treatment
Recognizing
stakeholder
views
Aligned with
shareholders
21
Strategic reportBP Annual Report and Form 20-F 2013 Group performance
Our progress in 2013 has set us up well to deliver our
10-point plan and forms the foundations for delivering
value in the long term.
In May we completed the successful
commissioning of a state-of-the-art diesel
hydrotreater and hydrogen plant at the Cherry
Point refinery in Washington state.
The Mad Dog field in the Gulf of Mexico was
discovered in 1998 and is one of BP’s largest
discoveries in the Gulf of Mexico to date.
We continued to operate within a disciplined financial framework in 2013 – with organic capital
expenditurea of $24.6 billion (within the expected $24-$25 billion range). Upstream BP-operated plant
efficiencyb of 88% and strong refining availability of 95.3% in Downstream demonstrated our
progress in operational efficiency. We completed the transactions to increase our shareholding in
Rosneft to 19.75%. And, we are continuing to meet our commitments in the Gulf of Mexico, while
making our case in court.
2013-2014 milestones set out in our 10-point plan
Drilling up to 25 wells per year.
We completed 17 exploration wells and made seven potentially commercial discoveries in 2013.
It was our most successful year for exploration drilling in almost a decade.
A further nine major upstream project start-ups.
Three major projects were started up in 2013 and another three in January and February 2014.
We expect a further four major upstream projects to start up in 2014.
Unit operating cash marginsc from new upstream projects in 2014 are expected to be double
the 2011 average.d
We continued to bring on major projects in key regions such as Angola and the Gulf of Mexico.
Bringing onstream the major upgrade to the Whiting refinery in the second half of 2013.
We completed the commissioning of all major units for the refinery upgrade, transforming it into
one of our advantaged downstream assets in our portfolio.
Completing our $38-billion divestment programme by the end of 2013.
We completed our $38-billion divestment programme in 2012 – effectively a year early.
In October 2013, we announced our plan to divest a further $10 billion before the end of 2015.
We have a high-value, focused portfolio that plays to our strengths.
Our divestments have removed complexity, strengthened the balance sheet and left us with a
more distinctive set of assets that play to our strengths – deep water, gas value chains, giant
fields and high-quality downstream businesses.
Increasing overall operating cash flowe by 50% in 2014 compared with 2011.f
We are on track to meet our goal of generating more than $30 billion of operating cash flow in 2014.
We expect to use around half of the extra cash for increased investment and around half for
other purposes, including increased distributions to shareholders.
As at 31 December 2013 we had bought back 753 million shares for a total amount of $5.5 billion,
including fees and stamp duty, since 22 March 2013. The dividend paid in 2013 was 36.5 cents
per share, up 30% compared with the dividend of 28 cents per share paid in 2011.
Segment performance
For Upstream and Downstream
performance see pages 25 and 31
respectively.
a Organic capital expenditure excludes acquisitions, asset
exchanges, and other inorganic capital expenditure.
b See footnote a on page 25.
c See footnote f on page 13.
d See footnote g on page 13.
e See footnote a on page 56.
f See footnote b on page 56.
22
BP Annual Report and Form 20-F 2013 Group performance and outlook
Financial performance
Profit before interest and taxation
Finance costs and net finance
expense relating to pensions and
other post-retirement benefits
Taxation
Non-controlling interests
Profit for the yeara
Inventory holding (gains) losses, net
of taxb
Replacement cost profitc
Net charge (credit) for non-operating
2013
31,769
2012
19,769
$ million
2011
39,815
(1,548)
(6,463)
(307)
23,451
(1,638)
(6,880)
(234)
11,017
(1,587)
(12,619)
(397)
25,212
230
23,681
411
11,428
(1,800)
23,412
itemsd, net of tax
(10,533)
5,298
(2,195)
Net (favourable) unfavourable impact
of fair value accounting effectsd,
net of tax
Underlying replacement cost profitc
Capital expenditure and acquisitions
280
13,428
36,612
345
17,071
25,204
(47)
21,170
31,959
Segment RC profit (loss) before interest and tax ($ billion)
Rosneft
Upstream
Other businesses
and corporate
Group RC profit (loss) before interest and tax
Downstream
Gulf of Mexico
oil spill
TNK-BP
Unrealized profit
in inventory
45
35
25
15
5
(5)
(15)
(25)
(35)
(45)
2009
2010
2011
2012
2013
Profit for the year ended 31 December 2013 was $23,451 million. After
adjusting for $230 million in respect of inventory holding losses and their
associated tax effect, replacement cost (RC) profit was $23,681 million.
After further adjusting for a net credit of $10,533 million for non-operating
items and unfavourable fair value accounting effects (relative to
management’s measure of performance) of $280 million, both net of tax,
underlying RC profit was $13,428 million.
Non-operating items in 2013, on a pre-tax basis, were mainly relating to the
$12.5-billion gain on disposal of TNK-BP partially offset by an $845-million
write-off attributable to block BM-CAL-13 offshore Brazil as a result of the
Pitanga exploration well not encountering commercial quantities of oil or
a Profit attributable to BP shareholders.
b Inventory holding gains and losses represent the difference between the cost of sales calculated
using the average cost to BP of supplies acquired during the year and the cost of sales calculated
on the first-in first-out (FIFO) method, after adjusting for any changes in provisions where the net
realizable value of the inventory is lower than its cost. BP’s management believes it is helpful to
disclose this information. An analysis of inventory holding gains and losses by segment is shown
in Financial statements – Note 7 and further information on inventory holding gains and losses is
provided on page 269.
c Replacement cost (RC) profit or loss reflects the replacement cost of supplies and is arrived at by
excluding inventory holding gains and losses from profit or loss. RC profit or loss is the measure
of profit or loss for each operating segment that is required to be disclosed under International
Financial Reporting Standards (IFRS). RC profit or loss for the group is not a recognized GAAP
measure. Underlying RC profit or loss is RC profit or loss after adjusting for non-operating items
and fair value accounting effects. Underlying RC profit or loss and fair value accounting effects
are not recognized GAAP measures. For further information on RC profit or loss and underlying
RC profit or loss, see Certain definitions on page 269.
gas, impairment charges and further charges associated with the Gulf of
Mexico oil spill. More information on non-operating items, and fair value
accounting effects, can be found on page 237. See Gulf of Mexico oil spill
on page 38 and Financial statements – Note 2 for further information on
the impact of the Gulf of Mexico oil spill on BP’s financial results.
For the year ended 31 December 2012, profit was $11,017 million, RC profit
was $11,428 million and underlying RC profit was $17,071 million. There
was a net post-tax charge of $5,298 million for non-operating items, which
included a $5.0-billion pre-tax charge relating to the Gulf of Mexico oil spill.
Compared with 2012, underlying RC profit in 2013 was impacted by the
absence of equity-accounted earnings from TNK-BP and lower earnings
from both Downstream and Upstream, partially offset by the equity-
accounted earnings from Rosneft from 21 March 2013 (when sale and
purchase agreements with Rosneft and Rosneftegaz completed).
For the year ended 31 December 2011, profit was $25,212 million, RC profit
was $23,412 million and underlying RC profit was $21,170 million. There
was a net post-tax credit for non-operating items of $2,195 million, which
included a $3.8-billion pre-tax credit relating to the Gulf of Mexico oil spill.
Compared with 2011, underlying RC profit in 2012 was impacted by
significantly lower earnings from Upstream and the absence of equity-
accounted earnings from TNK-BP from 22 October 2012 (when our
investment was reclassified as an asset held for sale, as required under
IFRS), partially offset by improved earnings from Downstream.
See Upstream on page 25, Downstream on page 31, Rosneft on page 35
and Other businesses and corporate on page 37 for further information on
segment results.
Finance costs and net finance expense relating to pensions and other
post-retirement benefits
Finance costs comprise interest payable less amounts capitalized, and
interest accretion on provisions and long-term other payables.
Net finance expense relating to pensions and other post-retirement
benefits in 2013 was $480 million (2012 $566 million, 2011 $400 million).
In 2013, we adopted the revised version of IAS 19 ‘Employee Benefits’,
under which we apply the same expected rate of return on plan assets
as we used to discount our pension liabilities. Financial information for
prior periods has been restated – see Financial statements – Note 1 for
further information.
Taxation
The charge for income taxes in 2013 was $6,463 million (2012 $6,880
million, 2011 $12,619 million). The effective tax rate was 21% in 2013 (2012
38%, 2011 33%). The decrease in the effective tax rate in 2013 compared
with 2012 primarily relates to the gain on disposal of TNK-BP in 2013 for
which there was no corresponding tax charge. The increase in the effective
tax rate in 2012 compared with 2011 primarily reflects the impact of the
provision for the settlement with the US government relating to the Gulf of
Mexico oil spill, which is not tax deductible.
d Non-operating items are charges and credits arising in consolidated entities and in TNK-BP and
Rosneft that are included in the financial statements and that BP discloses separately because it
considers such disclosures to be meaningful and relevant to investors. The main categories of
non-operating items included here are: impairments; gains and losses on sale of businesses and
fixed assets; environmental remediation costs; restructuring, integration and rationalization costs;
and changes in the fair value of embedded derivatives. Fair value accounting effects are
non-GAAP adjustments to our IFRS profit relating to certain physical inventories, pipelines and
storage capacity. Management uses a fair-value basis to value these items which, under IFRS,
are accounted for on an accruals basis with the exception of trading inventories, which are valued
using spot prices. The adjustments have the effect of aligning the valuation basis of the physical
positions with that of the derivative instruments, which are required to be fair valued under IFRS,
in order to provide a more representative view of the ultimate economic value. See page 238 and
Certain definitions on page 269 for more information.
23
Strategic reportBP Annual Report and Form 20-F 2013 e Because of rounding, some totals may not agree exactly with the sum of their component parts.
f Liquids comprise crude oil, condensate and NGLs.
g Includes BP’s share of Rosneft and TNK-BP production. See Rosneft on page 36 and Oil and gas
disclosures for the group on page 245 for further information.
Total hydrocarbon proved reserves, on an oil equivalent basis including
equity-accounted entities, comprised 17,996mmboe (10,243mmboe
for subsidiaries and 7,753mmboe for equity-accounted entities) at
31 December 2013, an increase of 6% (decrease of 2% for subsidiaries
and increase of 18% for equity-accounted entities) compared with the
31 December 2012 reserves of 17,000mmboe (10,408mmboe for
subsidiaries and 6,592mmboe for equity-accounted entities). Natural gas
represented about 44% (58% for subsidiaries and 26% for equity-
accounted entities) of these reserves. The change includes a net increase
from acquisitions and disposals of 641mmboe (200mmboe net decrease
for subsidiaries and 841mmboe net increase for equity-accounted entities).
Net divestments in our subsidiaries occurred in the UK, the US, China and
Canada. We had sales and purchases, as a consequence of our divestment
of TNK-BP and investment in Rosneft.
Our total hydrocarbon production during 2013 averaged 3,230 thousand
barrels of oil equivalent per day (mboe/d). This comprised 1,887mboe/d for
subsidiaries and 1,343mboe/d for equity-accounted entities, a decrease of
4% (decreases of 2% for liquids and 6% for gas) and a decrease of 2%
(decrease of 2% for liquids and increase of 1% for gas) respectively
compared with 2012.
More information on reserves and production, see Oil and gas disclosures
for the group on page 245.
Critical accounting policies
The accounting policies, judgements, estimates and assumptions which
most affect the financial statements are described in Note 1 to the financial
statements.
Outlook
This discussion contains forward-looking statements, which by their
nature involve risk and uncertainty because they relate to events and
depend on circumstances that will or may occur in the future and are
outside the control of BP. You are urged to read Risk factors on page 51
and Cautionary statement on page 271, which describe the risks
and uncertainties that may cause actual results and developments to
differ materially from those expressed or implied by these forward-
looking statements.
We expect net cash provided by operating activities of between
$30-$31 billion in 2014.h
We expect capital expenditure, excluding acquisitions and asset
exchanges, to be around $24-$25 billion in 2014, and between
$24-$26 billion in the years 2015 to 2018.
We will continue to target our net debt ratio in the 10-20% range while
uncertainties remain. Net debt is a non-GAAP measure.
Depreciation, depletion and amortization in 2014 is expected to be
around $1 billion higher than in 2013.
For 2014, the underlying effective tax rate (ETR) (which excludes
non-operating items and fair value accounting effects) is expected to be
around 35%, which is the same as the underlying ETR in 2013.
Sources and uses of cash ($ billion)
Sources:
Operating cash flow
– rest of group
Uses:
Financing
Disposals
Capital expenditure
Dividends paid
Operating cash flow
– Gulf of Mexico oil spill
Net cash from
TNK-BP disposal
Share buybacks
50
40
30
20
10
Sources
Uses
2011
Sources
Uses
2012
Sources
Uses
2013
Operating cash flow
Operating cash flow is net cash provided by operating activities, as
presented in the group cash flow statement on page 125. Operating cash
flow in 2013 was $21.1 billion (2012 $20.5 billion, 2011 $22.2 billion).
Excluding the impact of the Gulf of Mexico oil spill, net operating cash flow
in 2013 was $21.2 billion (2012 $22.9 billion, 2011 $29.0 billion).
Shareholder distributions
Total dividends paid in 2013 were 36.5 cents per share, up 11% compared
with 2012 on a dollar basis and 12% in sterling terms. This equated to a
total cash distribution to shareholders of $5.4 billion during the year.
Group reserves and production
2013
2012
2011
Estimated net proved reserves
(net of royalties)a
Liquidsb
Subsidiaries
Equity-accounted entitiesc
Natural gas
Subsidiaries
Equity-accounted entitiesc
Total hydrocarbonsd
Subsidiaries
Equity-accounted entitiesc
Production (net of royalties)e
Liquidsf
Subsidiaries
Equity-accounted entitiesg
Natural gas
Subsidiaries
Equity-accounted entitiesg
Total hydrocarbonsd
Subsidiaries
Equity-accounted entitiesg
4,349
5,721
10,070
34,187
11,788
45,975
10,243
7,753
17,996
879
1,134
2,013
4,672
5,378
10,050
million barrels
5,331
5,234
10,565
billion cubic feet
36,381
5,278
41,659
million barrels of oil equivalent
11,604
6,144
17,748
33,264
7,041
40,305
10,408
6,592
17,000
thousand barrels per day
992
1,165
2,157
896
1,160
2,056
5,845
1,216
7,060
million cubic feet per day
6,193
6,393
1,200
1,125
7,518
7,393
thousand barrels of oil equivalent per day
2,094
1,963
1,360
1,367
3,454
3,331
1,887
1,343
3,230
a Volumes of equity-accounted entities include volumes of equity-accounted investments of those
entities.
b Liquids comprise crude oil, condensate, NGLs and bitumen.
c Includes BP’s share of Rosneft and TNK-BP reserves. See Rosneft on page 36 and
Supplementary information on oil and natural gas on page 200 for further information.
d Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
h Assumes $100/bbl oil and $5/mmBtu Henry Hub gas. The projection includes BP’s estimate of
the Rosneft dividend and the impact of payments in respect of federal criminal and securities
claims with the US government and SEC where settlements have already been reached, but
does not reflect any cash flows relating to other liabilities, contingent liabilities, settlements or
contingent assets arising from the Gulf of Mexico oil spill, which may or may not arise at that
time.
24
BP Annual Report and Form 20-F 2013 Upstream
In 2013 we continued to actively manage and simplify
our portfolio, strengthening our incumbent positions
to provide a platform for growing value.
Skarv started up in December 2012 and produces up to 160mboe/d. The
field development includes around 50 miles of gas export pipeline that
allows export to markets in Europe.
Our strategy is to invest to grow long-term value by continuing to
build a portfolio of material, enduring positions in the world’s key
hydrocarbon basins. Our strategy is enabled by:
• A continued focus on safety and the systematic management of risk.
• A simpler, more focused portfolio with strengthened incumbent
positions and reduced operating complexity.
• Playing to our strengths – exploration, deep water, giant fields
and gas value chains.
• An execution model that drives improvement in efficiency
and reliability – through both operations and investment.
• A bias to oil with selective gas value chains focusing on where we
have strong core positions, can play in premium growth markets or
bring advantaged technology to bear.
• Strong relationships built on mutual advantage, deep knowledge
of the basins in which we operate, and technology.
Our performance – 2013 summary
• We continue our focus on improving safety performance. For more
details on personal and process safety (see Safety on page 41).
• Our exploration function gained access to new potential resources
covering more than 43,000km2 in seven countries.
• In 2013 there were three major upstream project start-ups.
• We achieved an upstream BP-operated plant efficiencya of 88%.
• Disposal transactions generated $1.3 billion in proceeds in 2013.
Upstream profitability ($ billion)
RC profit before interest and tax
Underlying RC profit before interest and taxb
Our business model and strategy
Our Upstream segment is responsible for our activities in oil and
natural gas exploration, field development and production, and
midstream transportation, storage and processing. We also market
and trade natural gas, including liquefied natural gas, power and natural
gas liquids. In 2013 our activities took place in 27 countries.
40
30
20
10
28.3
25.1
26.4
25.2
22.9
19.7
22.4
19.6
16.7 18.3
2009
2010
2011
2012
2013
We deliver our exploration, development and production activities
through five global technical and operating functions:
See Financial performance on page 27 for an explanation of the main
factors influencing Upstream profit in 2013 compared with 2012.
• The exploration function is responsible for renewing our resource
base through access, exploration and appraisal, while the reservoir
development function is responsible for the stewardship of our
resource portfolio.
• The global wells organization and the global projects
organization are responsible for the safe, reliable and compliant
execution of wells (drilling and completions) and major projects,
respectively.
• The global operations organization is responsible for safe, reliable
and compliant operations, including upstream production assets and
midstream transportation and processing activities.
The delivery of these activities is optimized and integrated with
support from global functions with specialist areas of expertise:
technology, finance, procurement and supply chain, human
resources and information technology.
Technologies such as seismic imaging, enhanced oil recovery and
real-time data support our upstream strategy by helping to gain new
access, increasing recovery and reserves and improving production
efficiency (see Our distinctive capabilities on page 16).
We actively manage our portfolio and are placing increasing emphasis
on accessing, developing and producing from fields able to provide the
greatest value (this includes those with the potential to make the
highest contribution to our operating cash flow). We sell assets that we
believe have more value to others. This allows us to focus our
leadership, technical resources and organizational capability on the
resources we believe are likely to add the most value to our portfolio.
Outlook
• We have announced plans to establish a separate BP business to
manage our onshore oil and gas assets in the US lower 48, which
we expect to be operational in early 2015. Our goal is to build a
stronger, more competitive and sustainable business that we expect
to be a key component of BP’s portfolio in the future.
• We expect reported production in 2014 to be lower than 2013,
mainly due to the expiration of the Abu Dhabi onshore concession,
with an impact of around 140mboe/d, and divestments. After
adjusting for the impacts of the concession expiry, divestments and
entitlement effects in our production-sharing agreements (PSAs),
we expect underlying production to be higher in 2014.
• In addition to the Chirag oil, Mars B and Na Kika Phase 3 projects,
which started up in January and February, we expect a further four
major projects to come onstream in 2014, which will contribute to
the group’s plan to generate an increase of around 50% in operating
cash flow in 2014 compared with 2011.c
• Capital investment in 2014 is expected to increase, largely reflecting
the progression of our major projects.
a Plant efficiency is the actual production of a plant facility expressed as a percentage of total
achievable installed production capacity of the asset including the reservoir, well, plant and export
system.
b Underlying replacement cost (RC) profit before interest and tax is not a recognized GAAP
measure. See footnote c on page 23 for further information. The equivalent measure on an IFRS
basis is RC profit before interest and tax.
c See footnote b on page 56.
25
Strategic reportBP Annual Report and Form 20-F 2013 2013
2012
2011
108.66
111.67
$ per barrel
111.26
Natural gas prices
Natural gas prices continued to show wide differentials between regions in
2013, although widening of the differentials stagnated as US gas prices
recovered from their 2012 lows. The Henry Hub First of Month Index
averaged $3.65 in 2013, an increase of 31% versus 2012.
Henry Hub ($/mmBtu)
2013
2012
5-year range
15
12
9
6
3
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
The US natural gas market saw a gradual return to balance in 2013,
following the dramatic loss of heating demand in 2012 due to unusually
warm winter weather, which pushed gas prices down to 10-year lows.
A return to more normal weather in 2013 restored heating demand for
gas, which meant less pressure on gas to compete with coal for a share
of the power generation market, allowing gas prices to recover. US
gas supply continued to expand in 2013, reaching yet another record
production level, supported in particular by rising liquids-rich (wet)
gas production.
In Europe, gas prices at the UK National Balancing Point increased
by 14% to an average of 67.99 pence per therm for 2013. Record-low
inventory levels, coming out of a prolonged winter, coupled with
declining European gas production and continued diversion of LNG to
the higher-priced Asian market, caused European spot prices to climb
to a five-year high. European demand remained weak, especially in
power generation where gas remained uncompetitive against coal.
Global LNG supply expanded in 2013, following a contraction in supply
in 2012. However the LNG market remained tight, with continued
strong demand in Asia due to economic growth and nuclear power
outages, and also in Latin America due to the impact of a drought on
hydroelectric production.
In 2012 the strength of shale gas production in the US, combined with
an unusually warm winter, led the average Henry Hub First of Month
Index to fall by 31% to $2.79/mmBtu. In the UK, National Balancing
Point prices averaged 59.74 pence per therm, 6% above prices in 2011.
In 2014 we expect gas markets to continue to be driven by the
economy, weather, production, trade developments and continued
uncertainty surrounding nuclear power generation in Japan. Futures
markets indicate that the large gap between US and European gas
prices is expected to persist through 2014.
Our markets
Average oil marker pricesa
Brent
West Texas Intermediate
Average natural gas marker prices
Average Henry Hub gas priceb
97.99
3.65
94.13
95.04
$ per million British thermal units
4.04
pence per therm
2.79
Average UK National Balancing Point
gas pricea
67.99
59.74
56.33
a All traded days average.
b Henry Hub First of Month Index.
Crude oil benchmark prices
Brent remains an integral marker to the production portfolio, from which a
significant proportion of production is priced directly or indirectly. Certain
regions use other local markers, which are derived using differentials or a
lagged impact from the Brent crude oil price.
Crude oil prices, as demonstrated by the industry benchmark of dated
Brent, averaged $108.66 per barrel in 2013, compared with an average of
$111.67 per barrel in 2012. This represented the third consecutive year with
the dated Brent average price above $100 per barrel. Prices weakened in
early 2013 amid strong growth of light, sweet oil production in the US, but
rebounded later in the year due to a range of supply disruptions and
heightened market perceptions of risks to supply.
Brent ($/bbl)
2013
2012
5-year range
150
120
90
60
30
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
Amid continued high oil prices, global oil consumption increased, rising by
roughly 1.2 million barrels per day for the year compared with 2012 (1.3%),
in part boosted by cold weather early in the year.c The growth in
consumption was slightly exceeded by growth in non-OPEC production,
which was dominated by continued strong growth in US output. However,
OPEC crude oil production fell due to ongoing Iran sanctions and renewed
outages in Libya. As a result, OECD commercial oil inventories remained
relatively balanced.
Global oil consumption in 2012 grew by roughly 0.9 million barrels per day
compared with 2011 (0.9%).d OPEC production met most of the growth
in consumption, driven by the recovery in Libyan production.
We expect oil price movements in 2014 to continue to be driven by
the pace of global economic growth and its resulting implications for
oil consumption, by supply growth in North America, and OPEC production
decisions. Risks to supply remain a key uncertainty.
c From Oil Market Report 21 January 2014©, OECD/IEA 2014, page 1.
d BP Statistical Review of World Energy June 2013.
26
BP Annual Report and Form 20-F 2013
Preparing for Shah Deniz Stage 2
In 1999 we made one of our largest ever gas discoveries – Shah
Deniz – on the deepwater shelf of the Caspian Sea. The reservoir
is similar in size to Manhattan island and is being developed in
stages. Production from Stage 1 started in 2006.
Stage 2 will open up the Southern Gas Corridor so that gas can be
moved directly from Azerbaijan to Europe for the first time, helping
to increase the energy security of European markets. With a total
investment of more than $28 billion, this project will involve the
construction and integration of activity related to 26 wells, two
new platforms and onshore processing and compression facilities.
In 2013 we concluded 25-year sales agreements for more than
10 billion cubic metres per annum (bcma) to be produced from the
Shah Deniz field as a result of Stage 2 – the largest sales contracts
in Azerbaijan’s history. This adds to existing 2011 agreements to
sell 6bcma of gas, meaning that in total, 16bcma of Shah Deniz
Stage 2 gas is to be sold in Italy, Greece, Bulgaria and Turkey
through some 3,500km of pipelines to Europe. The agreements
came into force following the final investment decision on the
project on 17 December 2013.
We are strengthening our portfolio of high-value and longer
life assets.
Financial performance
Sales and other operating revenuese
RC profit before interest and tax
Net (favourable) unfavourable impact
of non-operating items and fair
value accounting effectsf
Underlying RC profit before interest
and taxg
Capital expenditure and acquisitions
BP average realizationsh
Crude oil
Natural gas liquids
Liquidsi
Natural gas
US natural gas
Total hydrocarbonsj
2013
70,374
16,657
2012
72,225
22,491
$ million
2011
75,754
26,358
1,608
(3,055)
(1,141)
18,265
19,115
105.38
38.38
99.24
19,436
18,520
25,217
25,821
$ per barrel
107.91
108.94
51.18
42.75
102.10
101.29
$ per thousand cubic feet
4.69
4.75
5.35
3.34
2.32
3.07
$ per thousand barrels of oil equivalent
62.31
61.86
63.58
e Includes sales to other segments.
f Fair value accounting effects are not a recognized GAAP measure and represent the (favourable)
unfavourable impact relative to management’s measure of performance (see page 238 for further
details).
g Underlying RC profit is not a recognized GAAP measure. See footnote c on page 23 for
information on underlying RC profit.
h Realizations are based on sales of consolidated subsidiaries only, which excludes equity-
accounted entities.
i Liquids comprise crude oil, condensate and natural gas liquids (NGLs).
j Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Sales and other operating revenues for 2013 were $70 billion (2012 $72
billion, 2011 $76 billion). The decrease in 2013, compared with 2012,
primarily reflected lower volumes due to disposals and lower realizations,
partially offset by higher gas marketing and trading revenues. The decrease
in 2012, compared with 2011, primarily reflected lower production and
persistently low Henry Hub gas prices.
In 2013 replacement cost (RC) profit before interest and tax for the segment
was $16.7 billion (2012 $22.5 billion, 2011 $26.4 billion). The 2013 result
included a net non-operating charge of $1,364 million, primarily related to an
$845-million write-off attributable to block BM-CAL-13 offshore Brazil as a
result of the Pitanga exploration well not encountering commercial quantities
of oil or gas, and impairment and other charges partly offset by fair value
gains on embedded derivatives and disposal gains. In addition, fair value
accounting effects had an unfavourable impact of $244 million relative to
management’s measure of performance. The 2012 result included net
non-operating gains of $3,189 million, primarily as a result of gains on
disposals being partly offset by impairment charges. In addition, fair value
accounting effects had an unfavourable impact of $134 million. The 2011
result included net non-operating gains of $1,130 million, primarily as a result
of gains on disposals being partly offset by impairments, a charge associated
with the termination of our agreement to sell our 60% interest in Pan
American Energy LLC (PAE) to Bridas Corporation and other non-operating
items. In addition, fair value accounting effects had a favourable impact of
$11 million.
After adjusting for non-operating items and fair value accounting effects,
underlying RC profit before interest and tax in 2013 was $18.3 billion (2012
$19.4 billion, 2011 $25.2 billion). Compared with 2012, the decrease in
2013 reflected lower production due to divestments, lower liquids
realizations and higher costs, including exploration write-offs and higher
depreciation, depletion and amortization, partly offset by an increase in
underlying volumes, a benefit from stronger gas marketing and trading
activities, a one-off benefit to production taxes as a result of fiscal relief
allowing immediate deduction of past costs, a one-off benefit, mainly in
respect of prior years, resulting from the US Federal Energy Regulatory
Commission approval of cost pooling settlement agreements between the
owners of the Trans-Alaska Pipeline System (TAPS) and higher gas
realizations. Compared with 2011, the 2012 result reflected higher costs
(primarily higher depreciation, depletion and amortization, as well as
ongoing sector inflation), lower production and lower realizations.
Total capital expenditure including acquisitions and asset exchanges in
2013 was $19.1 billion (2012 $18.5 billion, 2011 $25.8 billion).
Provisions for decommissioning decreased from $17.4 billion at the end of
2012 to $17.2 billion at the end of 2013. The decrease reflects primarily a
reduction due to the change in discount rate and utilization of provisions
largely offset by updated estimates of the cost of future decommissioning
and additions. Decommissioning costs are initially capitalized within fixed
assets and are subsequently depreciated as part of the asset.
Acquisitions and disposals
In total, disposal transactions generated $1.3 billion in proceeds during
2013, with a corresponding reduction in net proved reserves of
200mmboe, all within our subsidiaries. There were no significant
acquisitions in 2013.
Disposals
The major disposal transactions during 2013 were the sale of our
interests in the Harding (BP 70%), Maclure (BP 37.04%), Braes (BP 27.7%),
27
Strategic reportBP Annual Report and Form 20-F 2013
Major projects portfolio
Alaska
Canada
Alaska LNG
Liberty
Point Thomson
West end
development
Alaska viscous oil
Pike Phase 1
Sunrise Phase 1
Sunrise Phase 2
Terre de Grace
North Sea
Clair Ridge
Greater Clair
Kinnoull
Quad 204
Norway
Snadd
India
KG D6 R series
KG D6 satellites
KG D6 D55
Egypt
East Nile Delta low
pressure hub
West Nile Delta
Satis
Salamat
Azerbaijan
ACG future development
Chirag oil
Shah Deniz Stage 2
Gulf of Mexico
Atlantis North expansion
Phase 1
Mad Dog Phase 2
Mars B
Na Kika Phase 3
Atlantis North expansion Phase 2
Thunder Horse South expansion
Kaskida
Tiber
Moccasin
Key
Started up in 2013.
Started up in/on track for 2014 start-up.
In progress for 2015 and beyond.
North Africa
In Amenas compression
In Salah gas southern fields
Bourarhat
Trinidad & Tobago
Middle East
Oman Khazzan
Indonesia
Tangguh expansion
Sanga Sanga CBM
Juniper
Manakin
Angelin
Cassia
Brazil
Itaipu
Angola
Angola LNG
B18 PCC
B31 SE
CLOV
Greater Plutonio Phase 3
Kizomba satellites Phase 2
Zinia Phase 2
Australia
Browse
North Rankin Phase 2
Persephone
Western Flank Phase A
Western Flank Phase B
Braemar (BP 52%) and Devenick (BP 88.7%) fields in the North Sea to
TAQA Bratani Ltd for $1,058 million plus future payments which,
depending on oil price and production, are currently expected to exceed
$180 million after tax; and the sale of our interests in the Yacheng (BP
34.3%) field in China for $308 million, both of which are subject to
post-closing adjustments. More information on disposals is provided in
Upstream analysis by region on page 239 and Financial statements –
Note 5.
Exploration
The group explores for oil and natural gas under a wide range of licensing,
joint arrangement and other contractual agreements. We may do this alone
or, more frequently, with partners. BP acts as operator for many of these
ventures.
New access in 2013
We gained access to new potential resources covering more than
43,000km2 in seven countries (Canada, Brazil, Greenland, Norway, Egypt,
the UK and China). In addition, we entered into three farm-out agreements
with Kosmos Energy, covering around 25,000km2 over three blocks
offshore Morocco, one of which is still subject to government approval.
During the year we participated in seven potentially commercial discoveries
including the following that we announced: two off the east coast of India
on blocks KG D6 and CYD5; one in Egypt with the Salamat well in the East
Nile Delta; one in the pre-salt play of Angola with the Lontra well in Block
20, operated by Cobalt International Energy, Inc.; one in the Paleogene play
in the Gulf of Mexico with the Gila prospect; and one in Brazil on block
BM-POT-17 in the Potiguar basin, operated by Petrobras.
Exploration and appraisal costs
Exploration and appraisal costs, excluding lease acquisitions, were $4,811
million (2012 $4,356 million, 2011 $2,413 million). These costs included
exploration and appraisal drilling expenditures, which were capitalized within
intangible fixed assets, and geological and geophysical exploration costs,
which were charged to income as incurred. Approximately 47% of exploration
28
and appraisal costs were directed towards appraisal activity. We participated in
140 gross (41 net) exploration and appraisal wells in 11 countries.
Exploration expense
Total exploration expense of $3,441 million (2012 $1,475 million, 2011
$1,520 million) included the write-off of expenses related to unsuccessful
drilling activities in Brazil ($388 million), the UK North Sea ($262 million),
Angola ($232 million), the Gulf of Mexico ($210 million), Jordan ($121
million) and others ($91 million). It also included an $845-million write-off
associated with the value ascribed to block BM-CAL-13 offshore Brazil as
part of the accounting for the acquisition of upstream assets from Devon
Energy in 2011 and a $257-million write-off for costs relating to the Risha
concession in Jordan. In addition, exploration expense included an
$88-million credit related to a reduction in provisions for the
decommissioning of idle infrastructure, which is required by the Bureau of
Ocean Energy Management Regulation and Enforcement’s Notice of
Lessees 2010 G05 issued in October 2010.
Upstream reserves
Estimated net proved reserves
(net of royalties)
Liquidsa
Subsidiariesb
Equity-accounted entitiesc
Natural gas
Subsidiariesd
Equity-accounted entitiesc
Total hydrocarbons
Subsidiaries
Equity-accounted entitiesc
2013
2012
2011
4,349
745
5,094
34,187
2,517
36,704
10,243
1,179
11,422
million barrels
5,331
929
6,260
4,672
838
5,510
billion cubic feet
36,381
2,397
38,778
33,264
2,549
35,813
million barrels of oil equivalent
11,604
1,342
12,946
10,408
1,277
11,685
BP Annual Report and Form 20-F 2013
a Liquids comprise crude oil, condensate, NGLs and bitumen.
b Includes 21 million barrels (14 million barrels at 31 December 2012 and 20 million barrels at
31 December 2011) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.
c BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2013,
upstream operations in Abu Dhabi, Argentina and Bolivia, as well as some of our operations in
Angola and Indonesia, were conducted through equity-accounted entities.
d Includes 2,685 billion cubic feet of natural gas (2,890 billion cubic feet at 31 December 2012
and 2,759 billion cubic feet at 31 December 2011) in respect of the 30% non-controlling interest
in BP Trinidad & Tobago LLC.
Reserves booking
Reserves booking from new discoveries will depend on the results of
ongoing technical and commercial evaluations, including appraisal
drilling. The Upstream segment’s total hydrocarbon reserves, on an oil
equivalent basis including equity-accounted entities comprised
11,422mmboe (10,243mmboe for subsidiaries and 1,179mmboe for
equity-accounted entities) at 31 December 2013, a decrease of 2%
(decrease of 2% for subsidiaries and decrease of 8% for equity-
accounted entities) compared with the 31 December 2012 reserves of
11,685mmboe (10,408mmboe for subsidiaries and 1,277mmboe for
equity-accounted entities).
Proved reserves replacement ratio
The proved reserves replacement ratio is the extent to which
production is replaced by proved reserves additions. This ratio is
expressed in oil equivalent terms and includes changes resulting from
revisions to previous estimates, improved recovery and extensions and
discoveries. For 2013 the proved reserves replacement ratio for the
Upstream segment, excluding acquisitions and disposals, was 93% for
subsidiaries and equity-accounted entities, 105% for subsidiaries alone
and 30% for equity-accounted entities alone. For more information on
proved reserves replacement for the group, see page 247.
Developments
The map on page 28 shows our major development areas, which
include Alaska, Angola, Australia, Azerbaijan, Canada, Egypt, the
deepwater Gulf of Mexico and the UK North Sea.
Three major project start-ups were achieved in 2013: Atlantis
North expansion Phase 1 in the Gulf of Mexico; Angola LNG; and North
Rankin Phase 2 in Australia.
We made good progress in the four areas we believe most likely to
provide us with higher-value barrels – Angola, Azerbaijan, the North Sea
and the Gulf of Mexico.
• Angola – we had our first LNG cargo in June and at the end of 2013
around 1 million cubic metres of LNG had been produced. The Plutão,
Saturno, Vénus and Marte (PSVM) project reached plateau
production of 150mb/d and the Cravo, Lirio, Orquidea, Violeta (CLOV)
floating production storage and offloading vessel (FPSO) sailed away
from Angola Paenal in January 2014 to start the offshore hook-up and
commissioning campaign.
• Azerbaijan – the Shah Deniz consortium – a seven-member group
led by BP – selected the Trans Adriatic Pipeline to deliver gas
volumes from the Shah Deniz Stage 2 project to customers in
Greece, Italy and southern Europe. In August, 25-year sales
agreements were concluded for over 10bcma of gas, to be produced
from the Shah Deniz field as a result of Stage 2. This adds to existing
agreements to sell 6bcma in Turkey. The final investment decision on
the project was made in December.
• North Sea – we continued to see high levels of activity, including the
ramp-up of major project volumes, a significant level of turnaround
activity, progress in the major redevelopment of the west of Shetland
Schiehallion and Loyal fields, the installation of the platform jackets
on the Clair Ridge project, a major milestone, and the sale of a
number of non-strategic assets.
• Gulf of Mexico – we had 10 rigs operating at the end of the year, the
highest number ever. Atlantis North expansion Phase 1 started up in
April. Following our strategic divestment programme, we now have a
very focused portfolio with growth potential around four operated
and three non-operated hubs.
In April the decision was taken not to move forward with the existing
development plan for the Mad Dog Phase 2 project in the deepwater
Gulf of Mexico, as market conditions and industry cost inflation made
the project less attractive than previously modelled. This decision
resulted in an impairment of $159 million. BP and its co-owners
reviewed alternative development concepts and the current concept
being considered is a single production host designed for future
flexibility in evaluating how best to capture additional potential resource.
Development expenditure of subsidiaries incurred in 2013,
excluding midstream activities, was $13.6 billion (2012 $12.6 billion,
2011 $10.4 billion).
Production
Our oil and natural gas production assets are located onshore and
offshore and include wells, gathering centres, in-field flow lines,
processing facilities, storage facilities, offshore platforms, export systems
(e.g. transit lines), pipelines and LNG plant facilities. The principal areas
of production are Angola, Argentina, Australia, Azerbaijan, Egypt, Trinidad,
the UAE, the UK and the US.
Maximizing value at Mad Dog
We continually review the development concepts of our projects to make sure they maximize
value for shareholders. One example of this is Mad Dog Phase 2 in the Gulf of Mexico. The project
builds on the existing Mad Dog development, which is designed to process 80,000 barrels of oil and
60 million cubic feet of gas per day.
For Phase 2, we originally planned to develop the remaining resource potential of the Mad Dog field
through a large second platform. However, as we progressed the design and reviewed cost
estimates, it became clear that market conditions and industry cost inflation made that selected
concept less attractive than initially modelled.
As part of our commitment to efficient investments, we reviewed alternative lower-cost
development concepts to ensure that we optimize project value and make the best financial
choices. The current concept being considered consists of a subsea development with a single new
production host that has been designed for future flexibility, allowing capture of additional resource
potential.
We continue to review options to further enhance value including simplifying the topsides and
subsea design, optimizing the location and number of wells and evaluating the required time to
achieve first oil production. We expect the revised project to show improved economics compared
with the previous concept.
We select only the best options that maximize value.
29
Strategic reportBP Annual Report and Form 20-F 2013 Our total hydrocarbon production during 2013 averaged 2,256 thousand
barrels of oil equivalent per day (mboe/d). This comprised 1,887mboe/d
for subsidiaries and 369mboe/d for equity-accounted entities, a
decrease of 4% (decreases of 2% for liquids and 6% for gas) and an
increase of 4% (increase of 5% for liquids and no change for gas)
respectively compared with 2012. More information on production can
be found in Oil and gas disclosures for the group on page 245.
In aggregate, after adjusting for the impact of price movements on our
entitlement to production in our PSAs and the effect of acquisitions and
disposals, underlying production was 3.2% higher compared with 2012.
This primarily reflects new major project volumes in Angola, the North
Sea and the Gulf of Mexico.
The group and its equity-accounted entities have numerous long-term
sales commitments in their various business activities, all of which are
expected to be sourced from supplies available to the group that are not
subject to priorities, curtailments or other restrictions. No single
contract or group of related contracts is material to the group.
Gas marketing and trading activities
We market and trade natural gas, power and natural gas liquids (NGLs).
This provides us with routes into liquid markets for the gas we produce.
It also generates margins and fees from selling physical products and
derivatives to third parties, together with income from asset optimization
and trading. The integrated supply and trading function manages the
group’s trading activities in natural gas, power and NGLs. This means we
have a single interface with the gas trading markets and one consistent
set of trading compliance processes, systems and controls.
Gas and power marketing and trading activity is undertaken primarily in
the US, Canada and Europe to market both BP production and third-party
natural gas, to support group LNG activities and manage market price
risk, as well as to create incremental trading opportunities through the
use of commodity derivative contracts. Additionally, this activity
generates fee income and enhances margins from sources such as the
management of price risk on behalf of third-party customers. These
markets are large, liquid and historically volatile. Market conditions have
become more challenging in recent years as volatility and geographic
basis/seasonal spreads have fallen to very low levels with the emergence
of shale gas in the US and generally over-supplied markets in Europe.
However, the traded LNG business has benefited from wide price
variations between the main gas consuming regions of North America,
Europe and Asia. As part of the LNG strategy, during 2013 we entered
into a 20-year gas liquefaction tolling contract for 4.4 million tons per
annum capacity which is located in Texas, US.
The gas and power marketing and trading function operates primarily
from offices in Houston and London and employs around 1,200 people.
The group’s risk governance framework seeks to manage and oversee
the financial risks associated with this trading activity, which is
described in Financial statements – Note 19.
In connection with its trading activities, the group uses a range of
commodity derivative contracts, storage and transport contracts.
The range of contracts that the group enters into is described in Certain
definitions – commodity trading contracts on page 270.
Analysis by region
See Upstream analysis by region on page 239.
Discovering gas in India
In India, one of the fastest growing economies in the world, we operate
across the full gas value chain as part of our strategic alliance with
Reliance Industries. The relationship gives us a 30% share of key
deepwater basin blocks off the country’s east coast.
In 2013 we made two significant gas and condensate discoveries in the
Krishna-Godavari basin and the Cauvery basin, a key milestone for our
partnership with Reliance. Along with our exploration efforts to find new
oil and gas, we aim to add value to our existing production in India by
developing the gas we have already discovered.
These resources have the potential to help meet India’s growing
demand for energy, increasing gas supplied to market from 2018
onwards and improving energy security in the country.
We continue to grow our exploration position using our leading
subsurface capabilities.
2013
2012
2011
Production (net of royalties)a
Liquidsb
Subsidiaries
Equity-accounted entities
Natural gas
Subsidiaries
Equity-accounted entities
Total hydrocarbonsc
Subsidiaries
Equity-accounted entities
879
297
1,176
896
284
1,179
thousand barrels per day
992
294
1,285
million cubic feet per day
6,393
6,193
415
416
6,807
6,609
thousand barrels of oil equivalent per day
2,094
1,963
366
355
2,460
2,319
5,845
415
6,259
1,887
369
2,256
a Includes BP’s share of production of equity-accounted entities in the Upstream segment.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Liquids comprise crude oil, condensate and NGLs.
c Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
30
BP Annual Report and Form 20-F 2013 Downstream
2013 was a year of improved safety performance,
operational improvements and delivery of significant
milestones to enhance the quality of our portfolio.
Cherry Point refinery processes around 230,000 barrels of crude oil per day,
primarily for transportation fuels.
Our business model and strategy
Our Downstream segment is the product and service-led arm of BP,
focused on fuels, lubricants and petrochemicals. We have significant
operations in Europe, North America and Asia, and also manufacture
and market our products across Australasia, southern Africa and Central
and South America.
The segment comprises three businesses:
• Fuels – fuels value chains (FVCs) including refineries, fuels marketing
businesses and global oil supply and trading activities. We sell refined
petroleum products including gasoline, diesel, aviation fuel and LPG.
• Lubricants – manufactures and markets lubricants and related
products and services globally, adding value through brand,
technology and relationships, such as collaboration with original
equipment manufacturing partners.
• Petrochemicals – manufactures products at locations around the
world, using proprietary BP technology. These products are then
used by others to make vital consumer products such as paint,
plastic bottles and textiles.
We aim to operate all of our businesses as safe and reliable value
chains. We participate in multiple stages of each value chain as we
believe we can deliver greater returns from integration than from
owning a collection of discrete assets. These value chains, combined
with our advantaged manufacturing operations, supply and trading
capability and expertise in technology, allow us to pursue long-term
competitive returns and sustainable growth, serving customers and
promoting BP and our brands through high quality products.
We research, develop and deploy a wide range of technologies,
processes and techniques, aiming to enhance safety and risk
management, increase efficiency and reliability, improve our margins
and create new market opportunities.
Our strategy focuses on four priorities executed in a systematic and
disciplined way:
• Safety performance.
• High-quality downstream portfolio.
• Competitive returns.
• Material and growing cash flows for the group through exposure to
growth opportunities and markets.
This strategy is about winning sustainably in the markets where we
choose to participate. We seek to outperform the best competitor in a
region and do it safely; investing to strengthen our established positions
while maintaining overall capital employed, and still seeking to shift the
mix of participation and capital employed from established to growing
markets. We do this while operating within a stable financial framework
to deliver attractive returns and growth in earnings and cash flow.
The delivery of these activities is optimized and integrated with support
from global functions with specialist areas of expertise: technology,
finance, procurement and supply chain, human resources, global
business services and information technology.
Our performance – 2013 summary
• Our personal and process safety performance improved compared
with 2012 and 2011 (see Safety on page 41).
• We completed the commissioning of all major units for the Whiting
refinery modernization project, transforming it into one of our key
advantaged downstream assets and supporting our ability to deliver
increased cash flow in 2014 and beyond.
• We also completed the sales of our Texas City and Carson refineries.
• Lubricants achieved steady replacement cost (RC) profit before
interest and tax through our exposure to growth markets, technology
investments and targeted marketing programmes.
• In petrochemicals, we announced two new proprietary technologies
which we expect to lower manufacturing costs and increase
efficiency for the production of key products.
Downstream profitability ($ billion)
RC profit before interest and tax
Underlying RC profit before interest and taxa
5.6
4.9
6.0
5.5
6.5
2.9
2.9
3.6
7
6
5
4
3
2
1
3.6
0.7
2009
2010
2011
2012
2013
See Financial performance on page 32 for an explanation of the main
factors influencing Downstream profit in 2013 compared with 2012.
Outlook
• In 2014 we anticipate refining margins will remain under pressure
due to high gasoline stocks and new competitor capacity additions,
as well as weak demand in many markets.
• We expect the financial impact of refinery turnarounds in 2014 to be
lower than in 2013.
• Whiting continues to progressively increase heavy crude processing,
and we expect to reach heavy crude processing levels of 280,000
barrels per day during the second quarter 2014.
• We anticipate demand for lubricants in 2014 will be similar to 2013.
• We expect a similarly challenging environment for petrochemicals in
2014, characterized by excess supply.
• Capital expenditure is forecast to be slightly lower in 2014 than in
2013, post commissioning of all major units of the Whiting refinery
modernization project.
a Underlying RC profit before interest and tax is not a recognized GAAP measure. See footnote c
on page 23 for further information. The equivalent measure on an IFRS basis is RC profit before
interest and tax.
31
Strategic reportBP Annual Report and Form 20-F 2013 Our markets
Economic growth in 2013 varied widely, with certain economies shrinking
and others showing some signs of recovery. OECD oil consumption was
up slightly in 2013, rising for the first time since 2010. Demand in
non-OECD economies also continued to grow, but at a slower rate than
2012 partly due to reduced GDP growth, for example in India, South East
Asia and the Middle East.
In oil markets in 2013, European refineries were impacted by limited
economic options to process sour grades, such as Urals, and by the loss
of Libyan sweet crude supplies for much of the year. In addition, crude
supplies were constrained by the loss of Iranian oil due to US and European
trade embargoes and by ongoing decline in European oil production. This
was partially offset by Saudi Arabia crude production, which reached a
30-year high.
Non-OPEC oil supply increased by over 1 million barrels per day in 2013,
primarily in the US due to increased production of shale oil. North
American crudes remained cheaper than waterborne crudes of a similar
quality, such as European Brent and Gulf Coast LLS, due to increased
production, combined with logistical constraints in transporting inland
crude production to the coast. Our refineries, particularly Toledo and
Whiting in the US, benefited from a location advantage as they were
able to access these discounted crudes. In addition, these refineries
benefited from a wider discount of Canadian heavy to West Texas
intermediate (WTI) crude in 2013, a factor that will become increasingly
important to the BP refining portfolio in 2014 with the commissioning of
the Whiting refinery modernization project.
Refining marker margin
We track the margin environment by way of a global refining marker
margin (RMM). Refining margins are a measure of the difference between
the price a refinery pays for its inputs (crude oil) and the market price of its
products. Although refineries produce a variety of petroleum products, we
track the margin environment using a simplified indicator that reflects the
margins achieved on gasoline and diesel only. The RMM may not be
representative of the margin achieved by BP in any period because of BP’s
particular refinery configurations and crude and product slates. The RMM
does not include estimates of fuel costs or other variable costs.
Crude marker
2013
2012
$ per barrel
2011
Refining marker margin (RMM)
US North West
US Midwest
Alaska North
Slope
West Texas
Intermediate
Northwest Europe
Brent
Mediterranean
Azeri Light
Australia
Brent
BP average RMM
15.2
21.7
12.9
10.5
13.4
15.4
18.0
27.8
16.1
12.7
14.8
18.2
14.1
24.7
11.9
9.0
12.2
14.5
In February 2013 BP updated the RMM methodology and regions to
reflect the changes to our US portfolio after the refinery divestments and
account for trends in regional crude markets since the RMM was
established. The effect of this update is that the 2012 and 2011 BP average
RMMs were restated from $15.0 per barrel (as originally reported) to
$18.2 per barrel and from $11.6 per barrel to $14.5 per barrel, respectively.
32
Global refining marker margin ($/bbl)
2013
2012
5-year range
40
32
24
16
8
Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec
The average RMM for 2013 was $2.8 per barrel lower compared to 2012,
with a slightly stronger first half and falling sharply in the second half of the
year. However, it was higher than 2011. Margins in 2013 declined primarily
due to increased product and gasoline supply, high gasoline inventories,
competitor capacity additions and lower seasonal turnarounds.
Financial performance
Sale of crude oil through spot
and term contracts
Marketing, spot and term sales
of refined products
Other sales and operating revenues
Sales and other operating revenuesa
RC profit before interest and taxb
Fuels
Lubricants
Petrochemicals
Net (favourable) unfavourable impact
of non-operating items and fair
value accounting effectsc
Fuels
Lubricants
Petrochemicals
Underlying RC profit before interest
and taxb d
Fuels
Lubricants
Petrochemicals
2013
2012
$ million
2011
79,394
56,383
57,055
258,015
13,786
351,195
274,666
15,342
346,391
273,940
13,038
344,033
1,518
1,274
127
2,919
1,403
1,276
185
2,864
2,999
1,350
1,121
5,470
712
(2)
3
713
2,230
1,272
130
3,632
3,609
9
(19)
3,599
5,012
1,285
166
6,463
640
(100)
(1)
539
3,639
1,250
1,120
6,009
Capital expenditure and acquisitions
4,506
5,249
4,285
a Includes sales to other segments.
b Income from petrochemicals produced at our Gelsenkirchen and Mülheim sites is reported within
the fuels business. Segment-level overhead expenses are included within the fuels business.
c Fair value accounting effects are not a recognized GAAP measure and represent the (favourable)
unfavourable impact relative to management’s measure of performance (see page 238 for further
details). For Downstream, these arise solely in the fuels business.
d Underlying RC profit is not a recognized GAAP measure. See footnote c on page 23 for
information on underlying RC profit.
Sales and other operating revenues in 2013 were $351 billion (2012
$346 billion, 2011 $344 billion). This increase in 2013, compared with 2012
reflects increased crude sales volumes, largely offset by lower prices. The
increase in 2012, compared with 2011, reflected higher prices almost
offset by lower volumes and foreign exchange losses.
In 2013 RC profit before interest and tax for the segment was $2.9 billion
(2012 $2.9 billion, 2011 $5.5 billion). The 2013 result included a net
non-operating charge of $535 million, primarily relating to impairment
charges in our fuels business, versus charges of $3,172 million in 2012
mainly related to impairment charges and $602 million in 2011 for
impairment charges associated with our disposal programme, partially
offset by gains on disposal. In addition, fair value accounting effects had an
BP Annual Report and Form 20-F 2013
unfavourable impact of $178 million in 2013 versus an unfavourable impact
of $427 million in 2012 and a favourable impact of $63 million in 2011.
After adjusting for non-operating items and fair value accounting effects,
underlying RC profit before interest and tax was $3.6 billion (2012 $6.5
billion, 2011 $6.0 billion).
The fuels business delivered an underlying RC profit before interest and tax
of $2,230 million for the year (2012 $5,012 million, 2011 $3,639 million).
Compared with 2012, 2013 saw significantly weaker refining margins.
Margins were weakened by reduced throughput due to the planned crude
unit outage at our Whiting refinery and commissioning of the new units
that were part of the refinery modernization project and the absence of
earnings from the divested Texas City and Carson refineries. This was
partially offset by a significantly improved supply and trading contribution
and lower overall turnaround activity during the year. Compared with 2011,
the 2012 result reflected strong operations that enabled us to capture the
higher refining margin environment, partly offset by a lower supply and
trading contribution.
The lubricants business delivered an underlying RC profit before interest
and tax of $1,272 million for the year (2012 $1,285 million, 2011 $1,250
million). These results reflect sustained underlying performance for the
lubricants business.
The petrochemicals business delivered an underlying RC profit before
interest and tax of $130 million for the year (2012 $166 million, 2011 $1,120
million). Compared with 2012, the 2013 result reflected weaker product
margins resulting from over supply in certain markets partially offset by
lower turnaround activity in the US and Europe.
Our petrochemicals productiona of 13,943 thousand tonnes (kte) in 2013
was lower than the previous two years (2012 14,727kte, 2011 14,866kte)
due to the sale of our BPCM Kuantan PTA plant in 2012 as well as reduced
output in both years for commercial reasons given the low-margin
environment.
A summary of our interests in petrochemicals production capacity as at
31 December 2013 is provided on page 244.
a Petrochemicals production includes 1,494kte of petrochemicals produced at our Gelsenkirchen
and Mülheim sites in Germany for which the income is reported in our fuels business.
Our fuels business
The fuels strategy focuses largely on fuels value chains (FVCs) which
include large-scale, highly upgraded and feedstock advantaged refineries
that are integrated with logistics and marketing as well as fuels marketing
businesses primarily supplied by our global supply and trading organization.
The FVCs seek to optimize the activities of our assets across the supply
chain through: advantaged feedstock delivery to the refineries;
manufacture of high-quality fuels; distribution through pipeline and terminal
infrastructure; and marketing and sales to our customers on a regional
basis. This integration, together with a focus on excellent execution and
cost management as well as a strong brand, market presence and
customer base, are key to our financial performance.
Refining
At 31 December 2013 we owned or had a share in 14 refineries producing
refined petroleum products that we supply to retail and commercial
customers. A summary of our interests in refineries and average daily
crude distillation capacities as at 31 December 2013 is provided on
page 243. As part of our plan to reshape BP’s US fuels business, we
completed the sales of the Texas City and Carson, California refineries and
associated logistic and marketing assets. The Texas City refinery and a
portion of our retail and logistics network in the south-east US were sold to
Marathon Petroleum Corporation on 1 February 2013 for consideration of
up to $2.5 billion. On 3 June 2013 we completed the sale of the Carson
refinery in California, ARCO network and related regional logistics assets to
Tesoro Corporation for approximately $2.4 billion.
Strategic investments in our refineries are focused on maintaining the
safety and reliability of our assets while improving unit margins versus the
competition. The most important of these strategic investments in 2013
was the Whiting refinery modernization project. During the year the new
coker, crude oil unit, gasoil hydrotreater, and an upgraded sulphur recovery
complex were all commissioned. We plan to progressively ramp up heavy
crude processing to approximately 280,000 barrels per day during the
second quarter of 2014. This major investment transforms Whiting into
one of the key advantaged downstream assets in our portfolio, with the
capacity to process a greater proportion of heavy crudes, and underpins
our ability to deliver increased cash flow from 2014 onwards.
Refinery operations were strong this year, with Solomon refining
availability of 95.3%. Utilization rates were at 86% principally due to the
planned crude unit outage at our Whiting refinery as part of the
modernization project. Overall refinery throughputs in 2013 were lower
than those in 2012, mostly driven by the divestment of the Texas City and
Carson refineries and associated logistics and marketing activities in 2013.
Creating our North American
advantaged refinery
We are creating a portfolio of advantaged
refineries in North America. At our Whiting
refinery we’ve commissioned all the major units
for our largest project in recent history, helping us
move towards that goal.
We built or reconfigured almost every process unit
as part of the modernization project. This included
new crude distillation and coking units and improved
hydro-treating sulphur recovery and increasing
coking capacity. Across the 1,400 acre site we
installed around 380 miles of pipe – more than
enough to run from London, England to Glasgow in
Scotland. This work has improved productivity and
safety at the refinery, creating the potential to
increase our heavy sour crude processing.
This, combined with Whiting’s advantaged Midwest
location, gives us the additional flexibility to process
crude from three major geographic sources
(Canada, US mid-continent and Gulf Coast),
supporting our ability to deliver increased cash flow.
Our Downstream business provides
significant cash generation for the group.
33
Strategic reportBP Annual Report and Form 20-F 2013 Refinery throughputsa
US
Europe
Rest of world
Total
Refining availabilityb
Sales volumes
Marketing salesc
Trading/supply salesd
Total refined product sales
Crude oile
Total
2013
726
766
299
1,791
95.3
3,084
2,485
5,569
2,142
7,711
2012
1,310
751
293
2,354
thousand barrels per day
2011
1,277
771
304
2,352
%
94.8
thousand barrels per day
94.8
3,213
2,444
5,657
1,518
7,175
3,311
2,465
5,776
1,532
7,308
a Refinery throughputs reflect crude oil and other feedstock volumes.
b Refining availability represents Solomon Associates’ operational availability, which is defined as
the percentage of the year that a unit is available for processing after subtracting the annualized
time lost due to turnaround activity and all planned mechanical, process and regulatory
maintenance downtime.
c Marketing sales include sales to service stations, end-consumers, bulk buyers and jobbers
(i.e. third parties who own networks of a number of service stations) and small resellers.
d Trading/supply sales are sales to large unbranded resellers and other oil companies.
e Crude oil sales relate to transactions executed by our integrated supply and trading function,
primarily for optimizing crude oil supplies to our refineries and in other trading. Fifty-nine thousand
barrels per day relate to revenues reported by the Upstream segment.
Logistics and marketing
Downstream of our refineries, we operate an advantaged infrastructure
and logistics network which includes pipelines, storage terminals and road
or rail tankers, where we seek to drive excellence in operational and
transactional processes, and deliver compelling customer offers in the
various markets in which we operate.
We blend and market biofuels in our FVCs; almost 6.5 billion litres of
biofuels were blended into finished product in 2013, mainly in Europe and
the US. Biogasoline (bioethanol) and biodiesel (hydrogenated vegetable oils
and fatty acid methyl esters) demand continues to grow, primarily in
Europe and the US, as regulatory requirements demand higher blending
levels. In response we continue to develop blend capabilities and to work
with regulators, biofuels suppliers and other stakeholders to improve the
sustainability of the biofuels we blend and supply.
We supply fuel and related convenience services to retail consumers
through company-owned and franchised retail sites, as well as other
channels, including wholesalers and jobbers. In addition, we supply
commercial customers within the transport and industrial sectors.
Retail sitesf
US
Europe
Rest of world
Total
Number of retail sites operated under a BP brand
2013
7,700
8,000
2,100
17,800
2012
10,100
8,300
2,300
20,700
2011
11,300
8,200
2,300
21,800
f The number of retail sites includes sites not operated by BP but instead operated by dealers,
jobbers, franchisees or brand licensees that operate under a BP brand. These may move to or
from the BP brand as their fuel supply or brand licence agreements expire and are renegotiated in
the normal course of business. Retail sites are primarily branded BP, ARCO and Aral. Excludes
our interests in equity-accounted entities that are dual-branded.
Supply and trading
BP’s integrated supply and trading function is responsible for delivering
value across the overall crude and oil products supply chain. This structure
enables the optimization of BP’s FVCs to maintain a single interface
with the oil trading markets and to operate with a single set of trading
compliance processes, systems and controls. The oil trading function
(including support functions) has trading offices in Europe, the US and
Asia and employs around 1,800 people. This enables the function to
maintain a presence in the more actively traded regions of the global oil
markets in order to gain an overall understanding of the supply and
demand forces across this market. It has a two-fold strategic purpose
in our Downstream business.
First, it seeks to identify the best markets and prices for our crude oil,
source optimal feedstocks for our refineries, and provide competitive
supply for our marketing businesses. Wherever possible, the group will
34
look to optimize value across the supply chain. For example, BP will often
sell its own crude and purchase alternative crudes from third parties for
its refineries where this will provide incremental margin.
Second, the function seeks to create and capture incremental trading
opportunities by entering into a full range of exchange-traded commodity
derivatives, over-the-counter (OTC) contracts and spot and term contracts.
In order to facilitate the generation of trading margin from arbitrage,
blending and storage opportunities, it also owns and contracts for storage
and transport capacity.
The group’s risk governance framework seeks to manage and oversee the
financial risks associated with this trading activity, which is described in
Financial statements – Note 19.
The range of contracts that the group enters into is described in Certain
definitions – commodity trading contracts on page 270.
Aviation
Our global aviation business, Air BP, is one of the world’s largest and
best-known aviation fuels suppliers, serving many major commercial
airlines as well as the general aviation sectors. We have marketing sales
in excess of 465,000 barrels per day. Air BP’s strategic aim is to maintain
its position in the core locations of Europe and the US, while expanding its
portfolio in airports that offer long-term competitive advantage in material
growing markets such as Asia and South America.
LPG
We have neared completion of the sale of our global LPG marketing
business, which sells bulk and bottled LPG products. We will retain focus
on LPG when it is deeply integrated in refinery operations and autogas
sectors in order to optimize refinery and retail operations. As of
31 December 2013, the sales of the LPG business in six out of eight
countries had been completed. The remaining two countries are expected
to be completed in 2014.
Our lubricants business
Our strategy is to leverage technology, brand, and relationships, with a
focus on our premium brands, to deliver growth and sustainable returns.
Our lubricants business manufactures and markets lubricants and related
products and services to the automotive, industrial, marine, aviation and
energy markets across the world. Our key brands are Castrol, BP and Aral.
Castrol is a recognized brand worldwide and we believe it provides us with
a significant competitive advantage. In technology, we apply our expertise
to create quality lubricants and high performance fluids for customers in
on-road, off-road, air, sea and industrial applications globally. We divide our
lubricants business up into five customer sectors: automotive, marine,
industrial, aviation and energy.
We are one of the largest purchasers of base oil in the market, but have
chosen not to produce at scale in base oil or additives manufacturing.
Our participation in the value chain is focused on areas of competitive
differentiation and strength. These fall into three main areas:
• We develop formulation and the application of cutting-edge technologies.
• We create and develop product brands and clearly communicate their
benefits to our customers.
• We build and extend our relationships with customers so we can better
understand and meet their needs.
In 2013, the automotive sector saw signs of recovery in new passenger
vehicle demand across several key markets including China, the US and
certain European countries. For 2013, lubricants base oil prices averaged
below 2012, which benefited margins. A significant share of profit growth
has come from emerging markets, where we are developing a strong base
to capture further growth.
The global lubricants market remained challenging in 2013 as a result of
economic slowdown and low demand growth. The automotive sector saw
declines in new passenger vehicle demand across Europe and India, which
were partially offset with growth in North America, China and Brazil.
Industrial demand remained under pressure from a weak manufacturing
sector.
We continue to increase lubricants revenues through our strategy of
exposure to growing markets, technology investments and targeted
marketing programmes. More than 35% of sales revenues were from
non-OECD countries in 2013.
BP Annual Report and Form 20-F 2013
Our lubricants business continued to increase the proportion of total sales
resulting from premium product sales; in 2013 the percentage of premium
sales was 40% compared with 39% in 2012 and 37% in 2011.
Rosneft
In January 2014, BP announced that it had agreed to sell its specialist
global aviation turbine oils business. The transaction, which is subject to
regulatory and other approvals, is expected to be completed in the second
quarter of 2014.
Our petrochemicals business
Our strategy is to own and develop petrochemical value chain businesses
which are built around proprietary technology. We apply this technology to
existing businesses and to access new growth markets where we wish to
build material shares. Overall, the business targets attractive absolute
returns and material, increasing cash flows by satisfying demand growth,
particularly in Asia.
We manufacture and market four main product lines:
• Purified terephthalic acid (PTA).
• Paraxylene.
• Acetic acid.
• Olefins and derivatives.
We also produce a number of other speciality petrochemicals products.
Our portfolio is underpinned with proprietary technology and leading cost
positions allowing BP assets to remain competitive against the newest
world-scale units being built in China. These capacity additions and
technology advances have resulted in a sharp fall in margins leading to
losses for the older, less efficient producers. New capacity additions are
targeted principally in the higher-growth Asian markets.
We both own and operate assets, and have also invested in a number of
joint arrangements in Asia, where our partners are leading companies
within their domestic market. For example, the construction of our new,
third PTA plant with our partner, Zhuhai Port Co. in Guangdong, China is
progressing well and is planned to begin production in late 2014. The
retro-fit of key elements of our PTA technology to existing plants is under
way. We expect these investments to have a material impact on efficiency
and reduce annual operating costs.
Our technology team develops, deploys and optimizes chemicals technology
to advance the competitiveness of the installed asset base and deliver
competitively advantaged projects to access growth. We plan to continue
deploying our technology in new asset platforms to access Asian demand
and advantaged feedstock sources.
In 2013 we announced two new proprietary petrochemicals technologies,
SaaBre and Hummingbird. SaaBre significantly reduces the cost of
production of acetic acid from syngas and avoids the need to purify carbon
monoxide or purchase methanol. SaaBre technology could also be used to
produce methanol and ethanol. Hummingbird simplifies the process of
converting ethanol to ethylene, a key component for the manufacture of
plastics. Hummingbird could open the way for the production of
biopolymers from bioethanol. Both technologies are expected to deliver
significant reductions in variable manufacturing costs and simplify the
manufacturing process.
In December 2013, we agreed to purchase all interests held by our
partners, Mitsui Chemicals, Inc. (MCI) and Mitsui & Co. Ltd. (MBK) in PT
Amoco Mitsui PTA Indonesia (AMI) which produces and markets PTA in
the Republic of Indonesia. This transaction completed on 28 February 2014
and is consistent with our strategy of growing our PTA business in our
chosen markets.
In September 2013, we signed a non-binding memorandum of
understanding with Oman Oil Corporation to assess jointly a facility in
Oman for the manufacture of acetic acid, deploying our SaaBre technology.
The economic environment for some of our products is likely to remain
under pressure in 2014. The impact of capacity additions in Asia continues
to depress margins for PTA. The environments for our acetic acid and
olefins and derivative value chains are expected to improve in the latter
part of 2014 as the high growth markets absorb excess capacity.
In March 2013 BP completed sale and purchase
agreements with Rosneft and Rosneftegaz.
Central processing and pumping facility at the Yuganskneftegaz field,
onshore Russia.
BP and Rosneft
• BP sold its investment in TNK-BP in exchange for $11.8 billion in cash
and an 18.5% stake in Rosneft. Together with its existing 1.25%
shareholding, BP now holds a 19.75% stake in the company.
• BP’s shareholding in Rosneft allows us to benefit from a diversified set
of existing and potential projects in the Russian oil and gas sector. BP
considers Rosneft share price appreciation and dividend growth as
primary sources of value for its shareholders.
• Rosneft’s strategy is to pursue sustainable growth of crude oil
production, develop its gas business and complete its refinery
modernization programme.
• BP is positioned to contribute to Rosneft’s strategy through the sharing
of technology, people, processes and best practice. We also have the
potential to undertake standalone projects with Rosneft, both in Russia
and internationally.
• Bob Dudley was elected to the Rosneft board of directors in June
2013, and became a member of the Rosneft board’s strategic planning
committee.
Rosneft – 2013 summary
• Rosneft announced in June 2013 that it had completed the process of
integrating TNK-BP and subsequently the Rosneft board approved a
modified business plan for 2013 incorporating the acquisition of
TNK-BP.
• Rosneft concluded long-term crude oil supply agreements with China
National Petroleum Corporation (CNPC) and Sinopec, signalling China
as an additional market for Russian crude.
• Rosneft completed the acquisition of the remaining 49% in the Itera
joint venture, 51% of Sibneftegaz and agreed to buy gas assets from
ALROSA.
• Rosneft made a voluntary offer in October 2013 to buy out the
non-controlling shareholders of RN Holding (formerly TNK-BP Holding).
By the closing date of the offer in January 2014, Rosneft had received
acceptances of its offer from over 98% of such shareholders.
35
Strategic reportBP Annual Report and Form 20-F 2013 BP’s share of the components of Rosneft’s net income are shown in the
table below.
Income statement (BP share)
Profit before interest and tax
Finance costs
Taxation
Non-controlling interests
Net income
Inventory holding (gains) losses, net of tax
Net income on a replacement cost basis
Net charge (credit) for non-operating items, net of tax
Net income on an underlying replacement cost basis
Balance sheet
Investments in associates
Production and reserves
Production (net of royalties) (BP share)e f
Liquids (mb/d)g
Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)h
Estimated net proved reserves (net of royalties)
(BP share)
Liquids (million barrels)g
Natural gas (billion cubic feet)
Total hydrocarbons (mmboe)
Average oil marker prices
Urals (Northwest Europe – CIF)
Russian domestic oil
$ million
2013a
2,786
(264)
(422)
(42)
2,058
100
2,158
45
2,203
$ million
31 December
2013
13,681
2013
650
617
756
4,975
9,271
6,574
$ per barrel
107.38
54.97
e Reflects production for the period 21 March to 31 December, averaged over the full year.
f Information on BP’s share of TNK-BP’s production for comparative periods is provided
on pages 248 and 250.
g Liquids comprise crude oil, condensate and natural gas liquids.
h Natural gas is converted to oil equivalent at 5.8 billion cubic feet = 1 million barrels.
Upstream
Rosneft is the largest oil company in Russia and the largest publicly traded
oil company in the world based on hydrocarbon production volume.
Rosneft also has significant hydrocarbon reserves.
Rosneft has assets in all key hydrocarbon regions of Russia: Western Siberia,
Eastern Siberia, Timan-Pechora, Volga-Urals, North Caucasus and Far East.
Internationally, Rosneft participates in exploration projects or has operations
in countries including the US, Canada, Vietnam, Venezuela, Brazil, Algeria,
UAE, Kazakhstan and Norway. Rosneft and Gazprom, the majority of whose
shares are owned by the Russian state, have exclusive rights to explore and
develop significant hydrocarbon resources in the Russian Arctic offshore
(including the Sea of Okhotsk). To progress Arctic exploration, Rosneft has
concluded partnerships with ExxonMobil, ENI, Statoil, CNPC and Inpex.
In 2013 Rosneft signed new gas sales contracts with Enel, Fortum and
others to monetize produced gas. Also Russian legislation introduced in
December 2013 allows Rosneft and Novatek to export LNG for the
first time.
Downstream
Rosneft has interests in 23 refineries including four in Germany through its
Ruhr Oel GmbH partnership with BP. In 2013 Rosneft acquired a 21%
share in the Saras S.p.A. refinery in Italy.
Rosneft refinery throughput in 2013 amounted to 1,818mb/d. Rosneft
continues to implement its refinery modernization programme which is
intended to significantly upgrade and expand its refining capacity. As at
31 December 2013, Rosneft owned and operated more than 2,400 retail
service stations, representing the largest network in Russia. This included
BP-branded sites acquired as part of Rosneft’s acquisition of TNK-BP which
will continue to operate under the BP brand. Rosneft’s downstream
operations also include jet fuel, bunkering, bitumen and lubricants.
Rosneft segment performance
BP’s investment in Rosneft is managed and reported as a separate
segment under IFRS. The Rosneft segment result includes equity-
accounted earnings from Rosneft, representing BP’s share in Rosneft and
foreign currency effects on the dividends received in 2013. For more
information on the sale and purchase agreements, see Financial
statements – Note 6.
Profit before interest and taxb c
Inventory holding (gains) losses
Replacement cost profit before interest and taxc
Net charge (credit) for non-operating items
Underlying replacement cost profit before interest and taxc d
$ million
2013a
2,053
100
2,153
45
2,198
a From 21 March 2013.
b BP’s share of Rosneft’s earnings after finance costs, taxation and non-controlling interests
is included in the BP group income statement within profit before interest and taxation.
c Includes $5 million of foreign exchange losses arising on the dividend received. This amount
is not reflected in the following table.
d Underlying replacement cost profit is not a recognized GAAP measure. See footnote c on page
23 for information on underlying replacement cost profit.
Replacement cost profit before interest and tax for the Rosneft segment
was $2.2 billion in 2013. The result included a net non-operating charge of
$45 million, primarily relating to impairment charges. After adjusting for
non-operating items, underlying replacement cost profit before interest
and tax in 2013 was $2.2 billion.
BP received a dividend from Rosneft in 2013 of $456 million, after the
deduction of withholding tax.
BP completed the exercise to determine the fair value of its share of
Rosneft’s assets and liabilities as at 21 March 2013, as required under
IFRS, and the results of this exercise are reflected in the 2013 reported
amounts.
36
BP Annual Report and Form 20-F 2013
Other businesses
and corporate
Other businesses and corporate comprises the Alternative Energy
business, Shipping, Treasury (which includes interest income on the
group’s cash and cash equivalents), and corporate activities including
centralized functions.
Financial performance
Sales and other operating revenuesa
Replacement cost profit (loss) before
2013
1,805
2012
1,985
$ million
2011
2,957
interest and tax
(2,319)
(2,794)
(2,468)
Net (favourable) unfavourable impact
of non-operating items
421
798
822
Underlying replacement cost profit
(loss) before interest and taxb
(1,898)
(1,996)
(1,646)
Capital expenditure and acquisitions
1,050
1,435
1,853
a Includes sales to other segments.
b Underlying replacement cost profit (loss) is not a recognized GAAP measure. See footnote c on
page 23 for information on underlying replacement cost profit (loss).
The replacement cost loss before interest and tax for the year ended
31 December 2013 was $2.3 billion (2012 $2.8 billion, 2011 $2.5 billion).
The 2013 result included a net charge for non-operating items of
$421 million (2012 $798 million, 2011 $822 million).
After adjusting for non-operating items, the underlying replacement cost
loss before interest and tax for the year ended 31 December 2013 was
$1.9 billion (2012 $2.0 billion, 2011 $1.6 billion). This result reflected higher
income on cash balances and lower corporate costs. The 2012 result was
impacted by the loss of income from the sale of the aluminium business in
2011, adverse foreign exchange effects and higher corporate costs.
Alternative Energy
BP is committed to alternative energy and our strategy is focused on
operating large scale businesses and commercializing our innovative
technologies. BP continues to invest in expanding the scale of our biofuels
business and in leveraging our unique capabilities and experience in
agri-business, bio-technology and bio-refining. We also have an operating
wind business. As at 31 December 2013, we have invested approximately
$8.3 billionc, exceeding our 2005 commitment of $8 billion over 10 years.
c The majority of costs were initially capitalized, although some were expensed under IFRS.
Biofuels
BP believes that it has a key role to play in enabling the transport sector to
respond to the dual challenges of energy security and climate change. We
have a focused programme of biofuels development based on the most
efficient transformation of sustainable and low-cost sugars into a range of
fuel molecules. Our strategy is to focus on the conversion of cost-
advantaged feedstocks that are materially scalable and that can be
competitive in an $80/bbl crude oil environment without subsidies.
We operate three sugar cane mills in Brazil producing bioethanol and sugar,
and exporting power to the grid. We continue to evaluate options to
increase production at these facilities and have already started work on
expanding ethanol production capacity at one mill and this work is
expected to be completed in 2014. Likewise, we are ramping up
production at our Vivergo joint venture plant, which is the largest
bioethanol facility in the UK and one of the largest in Europe. Once up to
full production capacity of 420 million litres per year, the Vivergo facility will
represent around 20% of the UK’s total 2012-13 requirements under the
Renewable Transport Fuels Obligation (RTFO).
BP continues to invest throughout the entire biofuels value chain, from
growing sustainable higher-yielding and lower-carbon feedstocks through
to the development, production and marketing of the advantaged fuel
molecule biobutanol, which has higher energy content than ethanol and
delivers improved fuel economy.
In conjunction with its partner DuPont, BP is undertaking leading-edge
research into the production of biobutanol under the company name
Butamax.
Across our biofuels business, BP’s share of ethanol-equivalent productiond
for 2013 was 521 million litres (552 million litres gross) compared with 404
million litres a year ago. The majority of this production is from BP’s sugar
cane mills in Brazil. In the US, BP has made the strategic decision to focus
its biofuels business on the research, development, and commercialization
of cellulosic ethanol technology at its facilities in San Diego, California, and
Jennings, Louisiana.
d Ethanol-equivalent production includes ethanol and sugar.
Wind
In wind power, our business is focused onshore in the US. In 2013 we
marketed our wind business for sale. Despite receiving a number of bids,
we determined it was not the right time to sell and instead are focusing on
optimizing performance at our 16 wholly owned and joint-venture wind
farms.
BP maintained its net wind generation capacity in the US at 1,558MWe
during 2013. BP’s net share of wind generation for 2013 was 4,203GWh
(7,363GWh gross), compared with 3,587GWh (5,739GWh gross) a year
ago.
e BP also has 32MW of wind capacity in the Netherlands, operated by our Downstream segment.
Emerging business and ventures
Our emerging business and ventures unit invests in technology
entrepreneurs working at the frontiers of their fields – across the entire
energy spectrum. Investments focus on emerging, strategic technologies,
oil and gas, downstream technologies including fuels and chemicals, and
biotech and bioenergy. The unit has made 37 separate investments, with
$210 million of committed capital.
Shipping
We transport our products across oceans, around coastlines and along
waterways using a combination of BP-operated, time-chartered and
spot-chartered vessels. All vessels conducting BP activities are subject to
our health, safety, security and environmental requirements. The primary
purpose of our shipping and chartering activities is the transportation of
our hydrocarbon products. In addition, we may use surplus capacity to
transport third-party products. In December 2013, BP announced it had
signed a contract with Hyundai Mipo Dockyard Co., Ltd to build 14 new
product tankers in Korea. The first of these will be delivered in 2016.
Treasury
Treasury manages the financing of the group centrally, ensuring liquidity is
sufficient to meet group requirements, and manages key financial risks
including interest rate, foreign exchange, pension and financial institution
credit risk. From locations in the UK, the US and Singapore, Treasury
provides the interface between BP and the international financial markets
and supports the financing of BP’s projects around the world. Treasury
trades foreign exchange and interest rate products in the financial markets,
hedging group exposures and generating incremental value through
optimizing and managing cash flows and the short-term investment of
operational cash balances. Trading activities are underpinned by the
compliance, control and risk management infrastructure common to all
BP trading activities. For further information, see Financial statements –
Note 19.
Insurance
The group generally restricts its purchase of insurance to situations where
this is required for legal or contractual reasons. Losses are borne as they
arise, rather than being spread over time through insurance premiums with
attendant transaction costs. This approach is reviewed on a regular basis
and if specific circumstances require such a review.
Outlook
In 2014 Other businesses and corporate annual charges, excluding
non-operating items, are expected to be in the range of $1.6-$2.0 billion.
37
Strategic reportBP Annual Report and Form 20-F 2013
Gulf of Mexico oil spill
We remain committed to meeting our
responsibilities to the US federal, state and local
governments and communities of the Gulf Coast
following the Deepwater Horizon accident.
Analysis of cumulative charges to the income statement
($ billion)
Spill response
Other fines
Environmental
Functional costs
Litigation and claimsa
Headroom remaining
Clean Water Act
penalties
0
5
10
15
20
25
30
35
40
45
a The litigation and claims cost is net of recoveries of $5.7 billion.
We have made significant progress in completing the response to the
accident and supporting economic and environmental recovery efforts in
affected areas.
Completing the response
BP, working under the direction of the US Coast Guard’s Federal On-Scene
Coordinator, continued to complete the Deepwater Horizon operational
response activities. By the end of 2013, operational activity continued on
just 37 of the approximately 4,400 shoreline miles in the area of response.
These 37 shoreline miles were all in Louisiana and were subject to
patrolling and maintenance, final monitoring or inspection, or were pending
final Coast Guard approval at the end of 2013. The US Coast Guard ended
active clean-up in Mississippi, Alabama and Florida in June 2013.
The US Coast Guard has indicated that if oil is later discovered in a
shoreline segment where removal actions have been deemed complete,
they will follow long-standing response protocols established under the
law and contact whoever it believes is the responsible party or parties.
Environmental restoration
BP is responsible for the reasonable and necessary costs of assessing
potential injury to natural resources resulting from the oil spill as well as the
reasonable and necessary costs of restoration as defined under the Oil
Pollution Act of 1990. In 2013 activity was focused on natural resource
damage assessment but some early restoration work has also begun.
Natural resource damage assessment
Scientists from BP, government agencies, academia and other
organizations are studying a range of species and habitats to understand
how wildlife populations and the environment may have been affected by
the accident and oil spill. Since May 2010, more than 240 initial and
amended work plans have been developed by state and federal trustees
and BP to study resources and habitat. The study data will inform an
assessment of injury to natural resources in the Gulf of Mexico and the
development of a restoration plan to address the identified injuries. By the
end of 2013, BP had paid approximately $1 billion to support the
assessment process.
Early restoration projects
While the injury assessment is still ongoing, restoration work has begun. In
April 2011 BP committed to provide up to $1 billion in early restoration
funding to expedite recovery of natural resources injured as a result of the
Deepwater Horizon accident and oil spill. BP and the trustees, as at
December 2013, had reached agreement or agreement in principle on a
total of 54 early restoration projects that are expected to cost
38
approximately $698 million, including 10 projects that are already in place
or under way.
Projects announced in 2013 include ecological projects that will restore
habitat and resources, as well as projects that enhance recreational use
of natural resources. These projects will proceed through a further
regulatory review and public comment process. Once that process is
complete, BP and the trustees will seek to proceed with approved projects.
BP will provide project funding in exchange for restoration credit to be
applied to the final assessment of natural resource damages.
Gulf of Mexico Research Initiative
In May 2010 BP committed $500 million over 10 years to fund
independent scientific research through the Gulf of Mexico Research
Initiative. The goal of the research initiative is to improve society’s ability to
understand, respond to and mitigate the potential impacts of oil spills to
marine and coastal ecosystems. As at 31 December 2013, the aggregate
contribution by BP was $169 million. The continued fulfilment of this
commitment is one of the conditions of the US government criminal plea
agreement (see below).
Economic recovery
BP continued to support economic recovery efforts in local communities
through a variety of actions and programmes in 2013. By 31 December
2013, BP had spent $12.8 billion on economic recovery, including claims,
advances, settlements and other payments, such as state tourism
grants and funding for state-led seafood testing and marketing. BP has
committed $2.3 billion to help resolve economic loss claims related to the
Gulf of Mexico seafood industry, of which $1.2 billion has been paid in to
the seafood compensation fund but has not yet been distributed to
final claimants.
Plaintiffs’ Steering Committee settlements
BP reached settlements in 2012 with the Plaintiffs’ Steering Committee
(PSC) to resolve the substantial majority of legitimate individual and
business claims and medical claims stemming from the accident and oil
spill. The PSC acts on behalf of individual and business plaintiffs in the
multi-district litigation proceedings in New Orleans (see Legal update
below). During 2013, amounts paid out under the PSC settlements totalled
$2.7 billion.
As part of its monitoring of payments made by the court-supervised
settlement programme for the economic and property damages
settlement, BP identified and disputed multiple business economic loss
claim determinations that appeared to result from an incorrect
interpretation of the economic and property damages settlement
agreement by the claims administrator. See further details under Legal
update below. BP has also raised issues about misconduct and inefficiency
in the facility administering the settlement.
The medical benefits class action settlement provides for claims to be
paid to qualifying class members from the agreement’s effective date.
Following the resolution of all appeals relating to this settlement, the
agreement’s effective date was 12 February 2014. The deadline for
submitting claims under the settlement is one year from the effective date.
OPA claims programme
There is a separate BP claims programme which handles claims under the
Oil Pollution Act of 1990 (OPA) by individuals and businesses who are not
covered by the PSC economic and property damages settlement, who
have opted out of the settlement or who are pursuing claims separately, as
permitted by the terms of the settlement. During 2013, amounts paid out
in relation to the OPA claims programme totalled $31 million.
State and local claims
Several states and local government entities have presented claims for
alleged losses, including economic and property damage, under OPA.
BP has provided for the current best estimate of the amount required to
settle these obligations. BP considers most of these claims to be
unsubstantiated and the methodologies used to calculate them to be
seriously flawed, not supported by OPA, not supported by documentation
and to be substantially overstated. A total of $89 million was paid in relation
to state and local claims in 2013.
For further information on the PSC settlements and state and local claims,
see Legal proceedings on page 257, Financial Statements – Note 2 and
bp.com/uslegalproceedings.
BP Annual Report and Form 20-F 2013 Legal update
BP is subject to a number of different legal proceedings in connection with
the Deepwater Horizon incident. These include the legal proceedings
relating to the PSC settlements; the multi-district litigation proceedings in
New Orleans; a range of civil lawsuits, including claims brought by states
and local government entities; other civil claims by individuals and
businesses; and the multi-district litigation proceedings in Houston in
relation to alleged violations of securities legislation. In 2012, BP reached a
settlement with the US Department of Justice relating to all federal
criminal charges and a settlement with the SEC resolving certain civil
claims. Certain BP entities have been subject to suspension and
debarment by the US Environmental Protection Agency (EPA).
PSC settlements
There have been various rulings from the district court and the US Court of
Appeals for the Fifth Circuit (Fifth Circuit) on matters relating to interpretation
of the PSC economic and property damages settlement agreement,
including the meaning of the causation requirements of the agreement.
In 2013 a panel of the Fifth Circuit (the business economic loss panel) set
aside the claims administrator’s interpretation of the business economic
loss framework of the settlement agreement and instructed the district
court in New Orleans to undertake additional proceedings to determine the
correct interpretation of the agreement. In December 2013, the district
court ruled that, for the purposes of determining business economic loss
claims, revenues must be matched with expenses incurred by claimants in
conducting their business even where the revenues and expenses were
recorded at different times. The district court assigned the development of
more detailed matching requirements to the claims administrator. The
claims administrator has issued a draft policy addressing the matching of
revenue and expenses for business economic loss claims. The parties
have made written submissions on the draft policy and the claims
administrator will issue a final policy to which BP and the PSC have the
right to object and seek review by the district court.
The district court also ruled that the settlement agreement did not contain
a causation requirement beyond the revenue and related tests set out in an
exhibit to that agreement. BP appealed the district court’s ruling on
causation to the business economic loss panel, but the panel affirmed the
district court’s ruling on 3 March 2014. BP is considering its appeal options,
including a potential petition that all the active judges of the Fifth Circuit
review the 3 March decision. The temporary injunction on business
economic loss claims offers and payments will be lifted when the case is
transferred back to the district court; the timing of this would be affected
by the status of any such petition by BP.
A separate but related appeal was brought by objectors to the economic
and property damages settlement challenging the overall fairness and
lawfulness of the agreement. This appeal was heard by a different panel of
the Fifth Circuit, which, in January 2014, upheld the district court’s
approval of the settlement agreement and left to the business economic
loss panel the question of how to interpret the agreement, including the
meaning of the agreement’s causation requirements. BP and several of the
objectors have filed petitions requesting that all the active judges of the
Fifth Circuit review the decision to uphold the approval of the settlement.
BP has filed a lawsuit alleging that it relied on fraudulent representations by
a former PSC lawyer when negotiating aspects of the PSC settlement
relating to the $2.3-billion seafood compensation fund. The district court
granted the lawyer’s motion to stay this lawsuit, pending developments in
the government’s criminal investigation and possible indictment. The
district court also denied BP’s motion requesting that further payments
from the seafood compensation fund be suspended on the basis that no
further payment from the fund is imminent. The district court deferred
ruling on a motion by BP seeking to determine the extent of the fraud and
what portion, if any, of the seafood fund should be returned as a result.
Multi-district litigation proceedings in New Orleans
The multi-district litigation trial relating to liability, limitation, exoneration
and fault allocation (MDL 2179) began in the federal district court in New
Orleans in February 2013. The first phase of the trial focused on the causes
of the accident and the allocation of fault among the defendants. The
second phase focused on efforts to stop the flow of oil and the volume of
oil spilled. BP is not aware of the timing of the district court’s rulings in
respect of these first two phases of the trial and the court could issue its
decision at any time.
In a subsequent trial phase, for which no trial date has yet been set, the
district court will consider the statutory per-barrel penalty rate to be applied
in determining penalties under the Clean Water Act. There is significant
uncertainty about the amount of Clean Water Act penalties to be paid, and
the timing of payment, as these will depend on the finding as to negligence
or gross negligence, the volume of oil spilled and the application of
statutory penalty factors. The district court has wide discretion in its
determination as to whether a defendant’s conduct involved negligence or
gross negligence as well as in its determinations on the volume of oil
spilled and the application of statutory penalty factors.
Civil claims
BP p.l.c., BP Exploration & Production Inc. (BPXP – the BP group company
that conducts exploration and production operations in the Gulf of Mexico)
and various other BP entities have been among the companies named as
defendants in approximately 2,950 civil lawsuits resulting from the accident
and oil spill, including the claims by several states and local government
entities referred to above. The majority of these lawsuits assert claims
under OPA, as well as various other claims, including for economic loss
and real property damage, and claims under maritime law and state law.
These lawsuits seek various remedies including economic and
compensatory damages, punitive damages, removal costs and natural
resource damages. Many of the lawsuits assert claims excluded from the
PSC settlements, such as claims for recovery for losses allegedly resulting
from the 2010 federal deepwater drilling moratoria and the related
permitting process. Many of these lawsuits have been consolidated with
the multi-district litigation proceedings in New Orleans.
Multi-district litigation proceedings in Houston
The MDL 2185 proceedings pending in federal court in Houston, including
a purported class action on behalf of purchasers of American Depository
Shares under US federal securities law, are continuing. A jury trial is
scheduled to begin in October 2014.
SEC settlement
In connection with the 2012 settlement with the SEC resolving the SEC’s
Deepwater Horizon-related civil claims, as of 31 December 2013, BP had
completed its first two payments totalling $350 million. A final $175 million
payment, plus accrued interest, is scheduled for 2014.
US government criminal plea agreement
Under the terms of the criminal plea agreement reached with the US
government in 2012 to resolve all federal criminal claims arising out of the
Deepwater Horizon incident, BP is taking additional actions, enforceable by
the court, to further enhance the safety of drilling operations in the Gulf of
Mexico. The first annual update on BP’s compliance with the plea
agreement is expected to be available by 31 March 2014 and to be
published at bpxpcompliancereports.com.
The plea agreement also provides for the US government to appoint two
independent monitors – a process safety monitor and an ethics monitor –
as well as an independent third-party auditor. The process safety monitor
has been retained, for a period of up to four years from February 2014, and
will review and provide recommendations concerning BPXP’s process
safety and risk management procedures for deepwater drilling in the Gulf
of Mexico. The ethics monitor has been retained, for a term of up to four
years from 2013, and will review and provide recommendations concerning
BP’s ethics and compliance programme. The third-party auditor has also
been retained and will review and report to the probation officer, the US
government and BP on BPXP’s compliance with the plea agreement’s
implementation plan.
US Environmental Protection Agency (EPA) suspension and
debarment
In November 2012, the EPA suspended BP p.l.c., BPXP and other BP
companies from receiving new federal contracts or renewing existing
ones. In 2013, the EPA debarred the Houston headquarters of BPXP, thus
effectively preventing it from entering into new contracts or leases with the
US government. In November 2013, the EPA continued the suspensions of
the previously suspended companies, suspended two new BP entities and
proposed discretionary debarment of all suspended BP entities. BP is
challenging the EPA’s suspension and debarment decisions. Neither the
suspensions nor the proposed debarments affect existing contracts BP
has with the US government, including those relating to current and
ongoing drilling and production operations in the Gulf of Mexico. BP
39
Strategic reportBP Annual Report and Form 20-F 2013 As at 31 December 2013, the cumulative charges to the Trust amounted to
$19.3 billion. Thus, a further $0.7 billion could be charged in subsequent
periods for items covered by the Trust with no net impact on the income
statement. Additional liabilities in excess of this amount would be
expensed to the income statement. See Legal proceedings on page 257
and Financial statements – Note 2 for more information.
Amounts payable from the Trust fund ($ billion)
3
1
2
1. Litigation and claims
and certain related costs
2. Environmental
3. Headroom
16.9
2.4
0.7
Clean Water Act penalties
BP has recognized a provision of $3.5 billion for the estimated civil
penalties for strict liability under the Clean Water Act, which are based on a
specified range per barrel of oil released. The penalty rate per barrel used
to calculate this provision is based upon BP’s conclusion, among other
things, that it did not act with gross negligence or engage in wilful
misconduct.
If BP is found to have been grossly negligent, the penalty is likely to be
significantly higher than the amount currently provided. See further details
under Multi-district litigation proceedings in New Orleans above and in
Financial statements – Note 2.
continues to work with the EPA in preparing an administrative agreement
to resolve these suspension and debarment issues.
For further information on these matters, see Risk factors on page 51 and
Legal proceedings on page 257.
Financial update
The group income statement for 2013 includes a pre-tax charge of $469
million in relation to the Gulf of Mexico oil spill. The charge for the year
reflects adjustments to provisions and the ongoing costs of the Gulf Coast
Restoration Organization. As at 31 December 2013, the total cumulative
charges recognized to date amount to $42.7 billion. BP has provided for
spill response costs, environmental expenditure, litigation and claims and
Clean Water Act penalties that can be measured reliably. At 31 December
2013, provisions related to the Gulf of Mexico oil spill amounted to
$9.3 billion (2012 $15.2 billion).
The cumulative income statement charge does not include amounts for
obligations that BP considers are not possible, at this time, to measure
reliably. Nothing is currently provided for natural resource damages,
except for $1 billion for early restoration projects and no provision has
been made for amounts arising from MDL 2185 (securities class action).
In addition, management believes that no reliable estimate can be made
of any business economic loss claims not yet received, processed and
paid. This is because of the significant uncertainties which exist currently,
as noted in the Plaintiffs’ Steering Committee section above (see also
Financial statements – Note 2). The additional amounts payable for these
and other items (such as state and local claims) could be considerable.
The total amounts that will ultimately be paid by BP in relation to all the
obligations relating to the accident and oil spill are subject to significant
uncertainty. The ultimate exposure and cost to BP will be dependent on
many factors, including any new information or future developments.
These could have a material impact on our consolidated financial condition,
results of operations and cash flows. The risks associated with the
accident and oil spill could also heighten the impact of the other risks to
which the group is exposed.
For details regarding the impacts and uncertainties relating to the Gulf of
Mexico oil spill, see Risk factors on page 51 and Financial statements –
Note 2.
Deepwater Horizon Oil Spill Trust update
BP, in agreement with the US government, set up the $20-billion
Deepwater Horizon Oil Spill Trust (the Trust) to provide confidence that
funds would be available to satisfy individual and business claims, final
judgments in litigation and litigation settlements, state and local response
costs and claims, and natural resource damages and related costs. The
Trust was fully funded by the end of 2012.
Payments made out of the Trust during 2013 totalled $3.1 billion for
individual and business claims, medical settlement programme payments,
natural resource damage assessment and early restoration, state and local
government claims, costs of the court supervised settlement progamme
and other resolved items. As at 31 December 2013, the aggregate cash
balances in the Trust and the associated qualified settlement funds
amounted to $6.7 billion, including $1.2 billion remaining in the seafood
compensation fund, which is yet to be distributed, and $0.9 billion held for
natural resource damage early restoration projects.
40
BP Annual Report and Form 20-F 2013
Corporate responsibility
We believe we have a positive role to play in shaping
the long-term future of energy.
We continue
Fire safety training in Angola.
Safety
We continue to promote deep capability and a safe operating
culture across BP.
• Our operating management system (OMS) is a group-wide
framework designed to provide a basis for managing our operations
in a systematic way.
• We continue to make progress on all of the remaining
recommendations from BP’s internal investigation regarding the
Deepwater Horizon accident (the Bly Report).
• We are focusing on developing deeper, longer-term relationships
with selected contractors in our Upstream business.
Loss of primary containment and tier 1 process safety events
(number of incidents)
Tier 1 process safety events
537
600
450
300
150
418
361
292
261
2009
2010
2011
2012
2013
Recordable injury frequency
(Workforce incidents per 200,000 hours worked)
American Petroleum Institute US benchmarka
International Association of Oil & Gas Producers benchmarka
1.0
0.8
0.6
0.4
0.2
2009
0.23
Employees
Contractors 0.43
2010
0.25
0.84
2011
0.31
0.41
2012
0.26
0.43
2013
0.25
0.36
a API and OGP 2013 data reports are not available until May 2014.
Group safety performance
In 2013 BP reported six fatalities. These were four employees in the
terrorist attack at In Amenas, Algeria and two contractors in heavy goods
vehicle incidents, one in Brazil and one in South Africa. We deeply regret
the loss of these lives.
Personal safety performance
Recordable injury frequency (group) –
incidents per 200,000
hours worked
Day away from work case frequencyb
(group) – incidents per 200,000
hours worked
2013
2012
2011
0.31
0.35
0.36
0.070
0.076
0.090
b Incidents that resulted in an injury where a person is unable to work for a day (shift) or more.
Process safety performance
Tier 1 process safety events
Loss of primary containment –
number of all incidentsc
Loss of primary containment –
number of oil spillsd
Number of oil spills to land and water
Volume of oil spilled (thousand litres)
Volume of oil unrecovered
(thousand litres)
2013
20
261
185
74
724
261
2012
43
292
204
102
801
320
2011
74
361
228
102
556
281
c Does not include either small or non-hazardous releases.
d Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).
We report tier 1 process safety events defined as the loss of primary
containment from a process of greatest consequence – causing harm to a
member of the workforce or costly damage to equipment, or exceeding
defined quantities. We use the American Petroleum Institute (API) RP-754
standard. Our loss of primary containment (LOPC) metric includes
unplanned or uncontrolled releases from a tank, vessel, pipe, rail car or
equipment used for containment or transfer of materials within our
operational boundary excluding non-hazardous releases such as water.
We seek to record all LOPCs regardless of the volume of the release and
report on losses over a severity threshold.
Managing safety
We are working to continuously improve safety and risk management
across BP. Three objectives guide our efforts:
• To promote deep capability and a safe operating culture across BP.
• To embed OMS as the way BP operates.
• To support self-verification and independent assurance that confirms our
conduct of operating.
Within BP, operating businesses are accountable for delivering safe,
compliant and reliable operations. They are supported in this by our safety
and operational risk (S&OR) function whose role is to:
• Set clear requirements.
• Maintain an independent view of operating risk.
• Provide deep technical support to the operating businesses.
• Intervene and escalate as appropriate to cause corrective action.
Governance
BP reviews risks at all levels of the organization. Each business segment
has a safety and operational risk committee, chaired by the business
head, to oversee the management of safety and risk in their respective
areas of the business. In addition, the group operations risk committee
(GORC) reviews safety and risk management across BP.
The board’s safety, ethics and environment assurance committee
(SEEAC) receives updates from the group chief executive and the head of
S&OR on management plans associated with the highest priority risks
as part of its update on GORC’s work. GORC also provides SEEAC
with updates on BP’s process and personal safety performance, and the
monitoring of major incidents and near misses across the group. See Our
management of risk on page 49.
41
Strategic reportBP Annual Report and Form 20-F 2013
We also maintain disaster recovery, crisis and business continuity
management plans and work to build day-to-day response capabilities to
support local management of incidents and group-wide practices and
response techniques. See page 44 for information on BP’s approach to oil
spill preparedness and response.
In January 2013, the In Amenas gas plant in Algeria, which is run as a joint
operation between BP, Sonatrach (the national gas company of Algeria)
and Statoil, came under armed terrorist attack. A total of 40 people from 10
countries and 10 organizations were killed in the attack. Four employees
and a former employee lost their lives in the incident. BP and Statoil jointly
carried out an extensive review of security arrangements in Algeria
following the attack and we are working with Sonatrach on implementing a
programme of security enhancements.
Safety in the Upstream business
Key safety metrics 2009-2013
Recordable injury frequency
Loss of primary containment
120
100
80
60
40
20
2009
2010
2011
2012
2013
Indexed (2009=100)
In our Upstream business the recordable injury frequency for 2013
remained stable at 0.32, the same as in 2012. Our day away from work
case frequency, incidents that resulted in an injury where a person is
unable to work for a day (shift) or more, was 0.068 in 2013 compared to
0.053 in 2012. The number of reported loss of primary containment
(LOPC) incidents was 143, down from 151 in 2012.
Safer drilling
Our global wells organization (GWO) is responsible for planning and
executing our wells operations across the world. It brings wells expertise
into a single organization to drive standardization and consistent
implementation. It is also responsible for establishing new GWO
standards on compliance, risk management, contractor management,
performance indicators, technology and capability.
We have been developing and finalizing OMS conformance plans for
activities which represent the highest risk areas in our wells operations.
For example we have developed and applied new and revised engineering
technical practices for activities such as well barriers and testing.
The Bly Report recommendations
BP’s investigation into the Deepwater Horizon accident in 2010, the Bly
Report, made 26 recommendations aimed at further reducing risk across
BP’s global drilling activities. They included strengthening contractor
management, improving assurance on blowout preventers, well control,
pressure-testing for well integrity, emergency systems, cement testing,
rig audit and verification, and personnel competence.
At the end of 2013, 15 of the Bly Report recommendations had been
completed. All 26 recommendations have been worked on in parallel and
progress has been made towards each of them. By the end of 2013, over
75% of the deliverables that make up the 26 recommendations had been
completed. A recommendation is defined as complete when it has been
approved by senior management in our global wells organization and
submitted for internal verification.
The outstanding recommendations relate to well control and well integrity,
drilling and competence, the management of risk and change, and
blowout preventers.
The board’s safety, ethics and environment assurance committee
monitors BP’s global implementation of the measures recommended in
the Bly Report, and progress is tracked quarterly by executive
A commitment to safe operations
Every day at Toledo refinery, a joint arrangement with Canada’s Husky
Energy, we make enough gasoline for around 3,200 cars to drive once
around the world. The site processes up to 160,000 barrels per day of
crude oil to make gasoline, diesel and other products, and has the
capability to refine a range of North American sourced crudes.
We strive to achieve an incident and injury-free environment at the
refinery, with everyone promoting safer working practices and making
sure incidents and near misses are reported. Workers demonstrated this
with their safe approach to the design, construction and commissioning
of the refinery’s naphtha reformer which increases energy efficiency and
reduces air emissions.
In November 2013, this commitment to safe, compliant and reliable
operations was recognized when the refinery passed 12 million work
hours without a day away from work injury – almost three years of work
– a new record in the site’s 93-year history.
Toledo has also continued to improve process safety with an 80%
reduction in reportable losses of primary containment in 2013 versus 2011.
We prioritize the safety and reliability of our operations.
Operating management system (OMS)
BP’s OMS is a group-wide framework designed to provide a basis for
managing our operations in a systematic way. OMS integrates BP
requirements on health, safety, security, environment, social responsibility
and operational reliability, as well as related issues such as maintenance,
contractor management and organizational learning, into a common
management system.
All BP businesses covered by the OMS are required to progressively align
with this framework through an annual performance improvement cycle.
Recently acquired operations need to transition to the OMS as the initial
step in this process. The application of a comprehensive management
system such as OMS across a global company is an ongoing process. See
page 44 for information about joint arrangements.
Capability development
BP’s capability development programmes are designed to equip our
staff with the skills needed to run safe and efficient operations. The
programmes cover our OMS, process safety and risk and safety
leadership. Our global wells institute offers courses in areas such as
applied deepwater well control, drilling engineering and well site
leadership with more than 100 sessions delivered in 2013. It includes a
simulator facility and an applied deepwater well control course where
drilling personnel, including our contractors, can work together and
practice a variety of well control situations. Trainers include experts from
both inside and outside of the oil and gas industry.
Security and crisis management
The scale and spread of BP’s operations means we must prepare for a
range of potential business disruptions and emergency events. BP
monitors for and aims to guard against hostile actions that could cause
harm to our people or disrupt our operations, including physical and digital
threats and vulnerabilities.
42
BP Annual Report and Form 20-F 2013 management. For the full report and periodic updates on progress see
bp.com/internalinvestigation.
We focus on the safe storage, handling and processing of hydrocarbons
in our facilities across the Downstream business. BP takes measures to:
• Prevent loss of hydrocarbon containment through well designed,
maintained and operated equipment.
• Reduce the likelihood of any hydrocarbon releases and the possibility
of ignition.
• Provide safe locations, emergency procedures and other mitigation
measures in the event of a release, fire or explosion.
Some areas where we worked to manage risks in our refining and
petrochemicals portfolio in 2013 included:
• Corrosion: Improving the way we detect, measure and monitor corrosion
with the aim of reducing the risk of leaks and increasing the reliability of
our equipment. We are using industry benchmarks and technology to
improve routine detection.
• Coaching: Nine manufacturing facilities participated in the Exemplar
programme which aims to help sites apply our operating management
system using continuous improvement processes.
• Site occupied buildings: We moved workforce further away from higher
risk processing areas at our petrochemical plant in Zhuhai, China and
installed an improved evacuation alert system at our chemical plant in
Hull in the UK, as part of a multi-year programme.
Process safety expert for our Downstream business
The board’s safety, ethics and environment assurance committee
appointed Duane Wilson in May 2012 as process safety expert and
assigned him to work in a global capacity with the Downstream business.
In his role as process safety expert, Mr Wilson provides an independent
perspective on the progress that BP’s fuels, lubricants and petrochemicals
businesses are making globally toward becoming industry leaders in
process safety performance. Mr Wilson’s contract has been extended to
April 2015.
Working with partners and contractors
BP, like all our industry peers, rarely works in isolation – we need to work
with suppliers, contractors and partners to carry out our operations. In
2013, 54% of the 373 million hours worked by BP were carried out
by contractors.
Our ability to be a safe and responsible operator depends in part on the
conduct of our suppliers and contractors. To this end we set operational
standards through legally-binding agreements. Training and dialogue also
help build the capability of our contractors.
Contractors
We expect our contractors to comply with legal and regulatory
requirements and to operate consistently with the principles of our code
of conduct when working on our behalf. Our OMS includes requirements
The Bly Report – independent assessment
The BP board appointed Carl Sandlin as independent expert to provide an
objective assessment of BP’s global progress in implementing the
deliverables from the Bly Report.
As part of his work, Mr Sandlin visited the regional wells teams with
active operation twice in 2013. During each visit Mr Sandlin conducted
reviews with their senior management and held discussions with key
wells personnel and drilling contractors onsite.
The BP board and Mr Sandlin have agreed, in principle, that his
engagement, initially scheduled to finish in June 2014, will be extended to
June 2016.
Process safety monitor
Following legal settlements with the US government in 2012, BP has
retained a process safety monitor for a term of up to four years from
February 2014. The process safety monitor will review and provide
recommendations concerning BP Exploration & Production Inc’s process
safety and risk management procedures for deepwater drilling in the Gulf
of Mexico.
Sharing lessons learned
We continue to share what we have learned to advance global deepwater
capabilities and practices that enhance safety in our company and the
deepwater industry. We have conducted more than 200 briefings over the
past three years to share lessons learned. We have worked with a range
of industry partners including trade associations, host governments,
national oil companies and regulators. For example we are working with
the International Association of Oil & Gas Producers, Marine Well
Containment Company, API and the International Association of Drilling
Contractors.
Safety in the Downstream business
Key safety metrics 2009-2013
Recordable injury frequency
Loss of primary containment
Process safety incident index
120
100
80
60
40
20
2009
2010
2011
2012
2013
Indexed (2009=100)
The process safety incident index (PSII) is a weighted index that reflects
both the number and severity of events per 200,000 hours worked. In
2013 our PSII was down 60% compared to a baseline year of 2009. There
were 101 LOPCs in 2013 down from 117 in 2012, with divestments
accounting for a significant part of this reduction.
We measure personal safety performance through recordable injury
frequency (RIF) and day away from work case frequency (DAFWCF) as
well as severe vehicle accident rate (SVAR). In 2013 our RIF was 0.25
compared to 0.33 in 2012. The 2013 DAFWCF, the number of cases
where an employee misses one or more days from work per 200,000
hours worked, was 0.063 compared to 0.089 in 2012.
Our SVAR which is the number of vehicle incidents that result in death,
injury, a spill, a vehicle rollover, or serious disabling vehicle damage per
one million kilometres travelled, was 0.10 in 2013 compared to 0.16 in
2012. Driving safety remains an area of focus for us.
A contractor checks a pump in the production module on the Thunder Horse
platform in the Gulf of Mexico, US.
43
Strategic reportBP Annual Report and Form 20-F 2013 and practices for working with contractors and our operations are obliged
to plan and execute actions to reach conformance with OMS on
contractor management.
We seek to set clear and consistent expectations of our contractors. In our
Upstream business our standard model contracts include, for example,
health, safety, security and environmental requirements.
Environment and society
Throughout the life cycle of our projects and operations,
we aim to manage the environmental and social impacts
of our presence.
Bridging documents are necessary in some cases to define how our
safety management system and that of our contractors co-exist to
manage risk on the work site.
In 2011 we undertook a review of how we manage contractors in our
Upstream business, which examined best practice in BP and other
industries that use contractors to perform potentially high-consequence
activities. As a result of this review, we are focusing on developing
deeper, longer-term relationships with selected contractors in our
Upstream business. We have:
• Established global agreements that help to strengthen our relationships
with strategic contractors and suppliers, manage risks more effectively
and leverage economies of scale.
• Increased the rigour of health and safety qualification and selection
criteria when approving contractor and supplier capabilities.
• Piloted guidance for the operating line on parts of our OMS that relate to
working with contractors.
• Continued working with our strategic contractors and suppliers to create
standardized technical specifications and quality requirements for certain
equipment, initially focused on new projects.
• Worked on incorporating safety and quality key performance metrics
into contracts for potentially high-consequence activities.
Our partners in joint arrangements
We seek to work with companies that share our commitment to ethical,
safe and sustainable working practices. However, we do not control how
our co-venturers and their employees approach these issues.
Typically, our level of influence or control over a joint arrangement is linked
to the size of our financial stake compared with other participants. Our
code of conduct provides that we will do everything we reasonably can to
make sure joint arrangements follow similar principles to those in our
code. In some joint arrangements we act as the operator. Our OMS
provides that where we are the operator, and where legal and contractual
arrangements allow, OMS applies to the operations of that joint
arrangement.
In other cases, one of our joint arrangement partners may be the
designated operator, or the operator may be an incorporated joint
arrangement company owned by BP and other companies. In those cases
our OMS does not apply as the management system to be used by the
operator, but is available to our businesses as a reference point for their
engagement with operators and co-venturers.
We introduced a group policy in 2013 to provide a consistent framework
for identifying and managing BP’s exposure related to safety and
operational risk, as well as bribery and corruption risk, from our
participation in new and existing non-operated joint arrangements.
44
• All of our major operating sites, with the exception of recently acquired
operations, were certified to the environmental management system
standard ISO 14001 in 2013.
• All of our businesses that have the potential to spill oil are updating oil
spill planning scenarios and response strategies.
• We are working towards aligning with the United Nations Guiding
Principles on Business and Human Rights.
• We actively monitor and report greenhouse gas emissions to improve
our understanding and management of potential carbon risks.
Greenhouse gas emissions
(Mte CO2 equivalent)
59.8
+0.1
–11.5
62.0
58.0
54.0
50.0
+1.0
–0.2
49.2
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Managing our impacts
At a group level, we review our management of material issues such as
GHG emissions, water, oil spill response, sensitive and protected areas
and human rights annually. Using our operating management system
(OMS), we seek to identify emerging risks and assess methods to reduce
them across the company.
Our OMS includes environmental and social practices that set out how
our major projects identify and manage environmental and social impacts.
The practices also apply to projects that involve new access, projects that
could affect an international protected area and some BP acquisition
negotiations.
In the early planning stages, these projects complete a screening process
to identify the most significant environmental and social impacts. Projects
are required to identify mitigation measures and implement these in
design, construction and operations. From April 2010 to the end of 2013,
91 projects had completed the screening process, and used outputs from
the process to implement measures to reduce negative impacts.
BP’s environmental expenditure in 2013 totalled $4,288 million (2012
$7,230 million, 2011 $8,491 million). This figure includes a credit of $66
million relating to the Gulf of Mexico oil spill. For reference, expenditure
related to the Gulf of Mexico oil spill was a charge of $919 million in 2012
and $1,838 million in 2011. See page 252 for a breakdown of
environmental expenditure. See Regulation of the group’s business –
Environmental regulation on page 254.
Oil spill preparedness and response
We issued new group-wide requirements for oil spill preparedness and
response planning, and crisis management in July 2012. These
incorporate what we have learned from the Deepwater Horizon accident.
All of our businesses that have the potential to spill oil have been updating
oil spill planning scenarios and response strategies in line with the
requirements.
Meeting the requirements is a substantial piece of work and we believe
this work has already resulted in a significant increase in our oil spill
BP Annual Report and Form 20-F 2013
response capability. For example, this includes using specialized modelling
techniques and the provision of response capabilities, such as stockpiles
of dispersants and planning for major offshore recovery operations.
Enhancing response capabilities
Improving our existing oil spill modelling tools helps BP to better define
different oil spill scenarios and associated response plans. For example,
following modelling for exploration in the Omani desert, we modified the
planned location of pipelines to reduce the impact to groundwater if a spill
were to occur.
We consider the environmental and socio-economic sensitivities of a
region to help inform oil spill response planning. Sensitivity mapping helps
us to identify the various types of habitats, resources and communities
that could potentially be impacted by oil spills and develop appropriate
response strategies. Sensitivity mapping is conducted around the world
and in 2013 we updated sensitivity maps in Angola, Australia, Azerbaijan,
Egypt, Libya, Trinidad & Tobago and the UK.
The use of dispersants is an important option in oil spill response planning.
We have gained a greater understanding of dispersants and their use as a
response option through scientific research programmes. We are
examining topics such as the effectiveness of dispersants in the deep
ocean and the efficiency of naturally occurring marine microbes to
degrade dispersed oil in the Gulf of Mexico and in the seas of Australia,
Azerbaijan and Egypt.
We seek to work collaboratively with government regulators in planning
for oil spill response, with the aim of improving any potential future
response. For example, in 2013 we shared lessons on dispersant use,
controlled burning response strategies and oil spill modelling with
government regulators in Azerbaijan, Brazil and Libya.
See page 42 for information on progress on the recommendations of BP’s
internal investigation into the Deepwater Horizon accident.
Climate change
Climate change represents a significant challenge for society and the
energy industry, including BP. In response to the challenges and
opportunities, BP is taking a number of practical steps, such as increasing
energy efficiency in our operations, factoring a carbon cost into the
investment and engineering decisions for new projects, and investing in
lower-carbon energy products. We also require our operations to
incorporate energy use considerations in their business plans and to
assess, prioritize and implement technologies and systems to improve
energy usage.
Climate change adaptation
We consider and identify risks and potential impacts of a changing climate
on our facilities and operations. Where climate change impacts are
identified as a risk for a new project, our engineers seek to address them
in the project design like any other physical and ecological hazard. We
periodically review and adjust existing design criteria and engineering
technology practices.
Greenhouse gas emissions
We report on GHG emissions on a carbon dioxide-equivalent (CO2e) basis.
This includes CO2 and methane for direct emissions and CO2 for indirect
emissions, which are associated with the purchase of electricity, heat or
steam into our operations. Our GHG reporting encompasses all BP’s
consolidated entities as well as our share of equity-accounted entities
other than BP’s share of TNK-BP and Rosneft. Rosneft’s emissions data
can be found on its website.
Our approach to calculating GHG emissions is aligned with the
Greenhouse Gas Protocol and the IPIECA/API/OGP Petroleum Industry
Guidelines for Reporting GHG Emissions. We calculate emissions based
on the fuel consumption and fuel properties for major sources rather than
the use of generic emission factors. We do not include nitrous oxide,
hydrofluorocarbons, perfluorocarbons and sulphur hexafluoride as they
are not material and therefore it is not practical to collect this data.
Greenhouse gas emissions
Direct GHG emissions (Mte CO2e)
Indirect GHG emissions (Mte CO2e)
2013
49.2
6.6
2012
59.8
8.4
2011
61.8
9.0
The decrease in our direct GHG emissions is primarily due to the
divestment of our Texas City and Carson refineries.
Intensity
The ratio of our total greenhouse gas emissions to adjusted revenue of
those entities (or share of entities) included in our GHG reporting was
0.15kte/$million in 2013. Adjusted revenue reflects total revenues and
other income, less gains on sales of businesses and fixed assets.
Additionally, we publish the ratios for greenhouse gas emissions to
upstream production, refining throughput and chemicals produced at
bp.com/greenhousegas.
Greenhouse gas regulation
In the future, we expect that additional regulation of GHG emissions
aimed at addressing climate change will have an increasing impact on
our businesses, operating costs and strategic planning, but may also
offer opportunities for the development of lower-carbon technologies
and businesses.
Accordingly, we require larger projects, and those for which emissions
costs would be a material part of the project, to apply a standard carbon
cost to the projected GHG emissions over the life of the project. The
standard cost is based on our estimate of the carbon price that might
realistically be expected in particular parts of the world. In industrialized
countries, our standard cost assumption is currently $40 per tonne of
CO2e. We use this cost as a basis for assessing the economic value of the
investment and as one consideration in optimizing the way the project is
engineered with respect to emissions.
Water
BP recognizes the importance of access to fresh water and the need
to manage water discharges at our operations. We assess risks, such
as water scarcity, wastewater disposal and the long-term social and
environmental pressures on water resources within the local area.
We are investing in research with several universities in the US to help
understand future risks in water management, such as the allocation
and use of water in the Middle East and the impact of water policies
and regulation around the world.
Unconventional gas and hydraulic fracturing
Natural gas resources, including unconventional gas, have an increasingly
important role in meeting the world’s growing energy needs. New
technologies are making it possible to extract unconventional gas
resources safely, responsibly and economically. BP has unconventional
gas operations in Algeria, Indonesia, Oman and the US.
Some stakeholders have raised concerns about the potential
environmental and community impacts of hydraulic fracturing. BP seeks to
apply responsible well design and construction, surface operation and
fluid handling practices to mitigate these impacts.
Water and sand constitute on average 99.5% of the injection fluid. This
is mixed with chemicals to create the fracturing fluid that is pumped
underground at high pressure to fracture the rock, with the sand propping
the fractures open. The chemicals used in the fracturing process help to
reduce friction and control bacterial growth in the well. Some of these
chemicals when used in certain concentrations are classified as hazardous
by the relevant regulatory authorities, and each chemical used in the
fracturing process is listed in the material safety data sheets kept at each
operational site. We submit data on chemicals used at our hydraulically
fractured wells in the US, to the extent allowed by our suppliers who own
the chemical formulas, at fracfocus.org.
We aim to minimize air pollutant and greenhouse gas emissions by using
responsible practices at our operating sites. For example, at our drilling sites
in the US we use a process called green completions, whenever possible, to
manage methane emissions associated with well completions following
hydraulic fracturing. This process recovers natural gas for sale and minimizes
the amount of natural gas either flared or vented from our wells.
45
Strategic reportBP Annual Report and Form 20-F 2013 • Participation in the work of oil and gas industry organization IPIECA’s
taskforce on developing shared industry approaches to managing human
rights risks in the supply chain.
We plan to monitor the effectiveness of these actions. More information
about our approach to human rights may be found at bp.com/humanrights.
Business ethics
Bribery and corruption are significant risks in the oil and gas industry.
Our code of conduct requires that our employees or others working on
behalf of BP do not engage in bribery or corruption in any form, whether
in the public or private sector. We operate a group-wide anti-bribery and
corruption standard, which applies to all BP employees and contractor
staff. The standard requires annual bribery and corruption risk
assessments; risk-based due diligence on all parties with whom BP does
business; appropriate anti-bribery and corruption clauses in contracts; and
the training of personnel in anti-bribery and corruption measures. Our
processes are designed to enable us to choose suppliers carefully on
merit, avoiding conflicts of interest and inappropriate gifts and
entertainment.
We are working to respond effectively to the standards arising from
the UK Bribery Act as well as other anti-corruption legislation such as
the Foreign Corrupt Practices Act and certain regulations promulgated
under the Dodd-Frank Wall Street Reform and Consumer Protection Act
(Dodd-Frank) in the US.
Financial transparency
As a member of the Extractive Industries Transparency Initiative (EITI),
we work with governments, non-governmental organizations and
international agencies to improve transparency and disclosure of
payments to governments. BP is supporting several countries that are
working towards becoming EITI compliant.
In countries that have achieved EITI compliance, including Azerbaijan and
Norway, BP submits an annual report on payments to their governments.
We have taken part in consultations in relation to new or proposed
revenue transparency reporting requirements in the US and EU for
companies in the extractive industries. We are awaiting the publication
of the revised rules of the Dodd-Frank legislation from the SEC and are
preparing to comply with the disclosure requirements.
We are contributing to the consultation process initiated by the UK
government in preparation for the adoption of the EU accounting directive
into UK law.
Enterprise and community development
In a number of BP locations, we run programmes to help build the skills of
businesses and to develop the local supply chain. For example, we have
helped some local companies reach the standards needed to supply BP
and other organizations through training and sharing of our standards in
areas such as health and safety.
BP’s social investments, the contributions we make to social and
community programmes in locations where we operate, support
development activities that aim for a meaningful and sustainable impact.
We look for social investment opportunities that are relevant to local
needs, aligned with BP’s business, and offer partnerships with local
organizations.
In 2013, we contributed $78.8 million in social investment. More
information about our social contribution can be found at
bp.com/society.
Environmental monitoring at our Terre de Grace oil sands lease area in
Northern Alberta, Canada.
We seek to design and locate our equipment and manage our work
patterns in ways that reduce potential impacts to communities such as
increased traffic, noise, dust and light. We also listen to suggestions or
complaints from nearby local communities and try to address their
concerns.
More information about our approach to unconventional gas and hydraulic
fracturing may be found at bp.com/unconventionalgas.
Canada’s oil sands
Oil sands in Canada are the third-largest proven crude oil reserves in the
world, after Saudi Arabia and Venezuela. About half of the world’s total oil
reserves that are open to private sector investment are contained in
Canada’s oil sands. BP is involved in three oil sands lease areas, all of
which are located in the province of Alberta. We expect the Sunrise
Energy Project, operated by Husky Energy, to be the first onstream with
production expected to begin in late 2014. Engineering and appraisal
activities are under way to design and plan the construction of the first
phase of Pike, which is operated by Devon Energy. Terre de Grace, which
is BP-operated, is currently under appraisal for development.
Our decision to invest in Canadian oil sands projects takes into
consideration GHG emissions, impacts on land, water use, local
communities and commercial viability. In the case of joint arrangements in
which we are not the operator, we monitor both the progress of these
projects and the mitigation of risk. In the Terre de Grace project where we
are the operator, we are responsible for managing these potential impacts
and the mitigation of risk.
More information on BP’s investments in Canada’s oil sands can be found
at bp.com/oilsands.
Human rights
BP’s human rights policy, published in 2013, outlines our commitment
to respect internationally-recognized human rights, as set out in the
International Bill of Human Rights and the International Labour
Organization’s Declaration on Fundamental Principles and Rights at
Work. The policy applies to all employees and officers in BP wholly
owned entities and in joint arrangements to the extent possible and
reasonable given BP’s level of participation.
The United Nations Guiding Principles on Business and Human Rights
outline specific responsibilities for businesses in relation to human rights.
We are committed to working towards aligning with the Guiding Principles
using a risk-based approach. In 2013 our actions included:
• Human rights workshops for senior leaders in Indonesia and the
Middle East, with plans to roll these out in other high-priority regions.
• Inclusion of human rights in our impact assessment for the LNG
expansion project in Tangguh, Indonesia.
• Collaboration with industry peers on the development of good practice
guidance for integrating human rights into environmental and social
impact assessments.
46
BP Annual Report and Form 20-F 2013 Employees
BP seeks employees who have the right skills for their roles
and who understand and embody the values and expected
behaviours that guide everything we do as a group.
• Our values and code of conduct define the expected qualities and
actions of all our people.
• We aim for a workforce that is engaged and that is representative of
the societies where we operate.
• We aim to develop the skills we need from within our existing
workforce and complement this with targeted external recruitment.
Our values
Safety
Respect
Excellence
Courage
One Team
BP headcount
Number of employees at 31 Decembera
2013
Upstream
Downstream
Other businesses and corporate
Gulf Coast Restoration Organization
2012
Upstream
Downstream
Other businesses and corporate
Gulf Coast Restoration Organization
2011
Upstream
Downstream
Other businesses and corporate
Gulf Coast Restoration Organization
a Reported to the nearest 100.
US
Non-US
Total
9,300
8,300
1,900
100
19,600
9,500
11,900
1,900
100
23,400
8,900
12,000
1,900
100
22,900
15,400
39,700
9,200
–
64,300
14,700
39,900
8,400
–
63,000
13,500
39,500
8,200
–
61,200
24,700
48,000
11,100
100
83,900
24,200
51,800
10,300
100
86,400
22,400
51,500
10,100
100
84,100
As at the end of December 2013, we had 83,900 employees. This includes
14,100 service station staff and 4,300 agricultural, operational and seasonal
workers in Brazil. The numbers for 2011 and 2012 have been restated
following the adoption of IFRS 11, see Financial statements – Note 1 for
further information.
During 2013, 4,300 people left BP through divestments, while there was
an increase in seasonal workers in our biofuels business – resulting in an
overall headcount decrease of 3% from 2012.
Our values
Our values of safety, respect, excellence, courage and one team
align explicitly with BP’s code of conduct and translate into the
responsible actions necessary for the work we do every day. Our values
represent the qualities and actions we wish to see in BP, they guide the
way we do business and the decisions we make. We are embedding
BP’s values into many of our group-wide systems and processes,
including our recruitment, promotion and development assessments.
See bp.com/values for more information.
People policies
We are focused on protecting the safety of our employees, engaging with
them, and increasing the diversity of our workforce so that it reflects the
societies in which we operate.
The group people committee, chaired by the group chief executive, has
overall responsibility for key policy decisions relating to employees. The
committee is responsible for governance of BP’s people management
processes. The committee discussed longer-term people priorities,
reward, progress in our diversity and inclusion programme, recruitment
priorities (including graduate recruitment), and improvements to our
learning and development programmes in 2013.
Attracting and retaining our people
The increasing demand for energy products and the complexity of our
projects means that attracting and retaining skilled and talented people
is vital to the delivery of our strategy and plans. We want to develop the
skills we need from within our existing workforce and we complement
this with targeted external recruitment.
To address increasing demand for skilled people across the globe, 44% of
our graduate recruitment came from universities outside the UK and US in
2013. We invest in universities worldwide to further develop the quality of
our potential recruits.
We conduct external assessments for all new hires into BP at senior levels
and for internal promotions to senior level and group leader level roles.
These assessments help achieve rigour and objectivity in our hiring and
talent processes. They give an in-depth analysis of leadership behaviour,
intellectual capacity and the required experience and skills for the role
being considered.
Building enduring capability
We provide development opportunities for all our employees, including
international assignments, mentoring, team development days,
workshops, seminars and online learning.
We continue to work to embed appropriate leadership skills throughout
our organization. By 2013 our group-wide suite of leadership development
programmes had been attended by employees from 32 countries and
were conducted in six different languages.
We provide leading education opportunities for our people through our
internal academies and institutes that deliver leadership development,
technical learning and compliance programmes.
Diversity
We are a global company and aim for a workforce that is representative of
the societies in which we operate.
We have set out our ambitions for diversity and our group people
committee reviews performance on a quarterly basis. We aim for 25% of
our group leaders – the most senior managers of our businesses and
functions – to be women by 2020.
Workforce by gender
Numbers as at 31 December
Board directors
Group leaders
Subsidiary directors
All employees
Male
12
477
494
58,500
Female
2
105
107
25,400
Female %
14
18
18
30
At the end of 2013, 22% of our group leaders came from countries other
than the UK and the US. We continue to increase the number of local
leaders and employees in our operations so that they reflect the
communities in which we operate and this is monitored at a local,
business or national level.
We support the UK government-commissioned Lord Davies review which
recommends increasing gender diversity on the boards of listed
companies. See page 70 for information on our board composition.
Inclusion
Our goal is to create an environment of inclusion and acceptance. For our
employees to be motivated and to perform to their full potential, and for
the business to thrive, our people need to be treated with respect and
dignity, and without discrimination.
47
Strategic reportBP Annual Report and Form 20-F 2013
Increasing oil production in Azerbaijan
Installing our ninth offshore platform in Azerbaijan, and eighth in the
Azeri-Chirag-Gunashli (ACG) field, involved local construction and
transportation of the heaviest structure ever installed in the Caspian Sea.
Thousands of people, mostly from Azerbaijan, contributed to the start-up
of the West Chirag platform in January 2014. For the first time in the
country’s history, the platform fabrication work was fully constructed in
Azerbaijan, making use of local infrastructure, resources and skilled labour.
Meeting the scale of the challenge meant that many facilities, including
the construction yard and installation vessels, had to be upgraded to make
the enormous construction works possible.
The $6-billion Chirag oil project is designed to increase our production and
recovery from the ACG field, and West Chirag has the capacity to produce
an additional 183,000 barrels of oil per day. The project was executed
without any day away from work cases recorded, demonstrating
dedication from everyone involved to maintain high safety standards.
We seek efficient ways to deliver projects on time and on budget.
We aim to ensure equal opportunity in recruitment, career development,
promotion, training and reward for all employees, including women; ethnic
minorities and different nationalities; lesbian, gay, bisexual and
transgender people; those with disabilities; and people of all ages. Where
existing employees become disabled, our policy is to provide continuing
employment and training wherever possible.
Employee engagement
Executive team members hold regular town hall style meetings and
webcasts to communicate with our employees around the world.
Team meetings and one-to-one meetings are complemented by formal
processes through works councils in parts of Europe. We seek to maintain
constructive relationships with labour unions.
We conduct an annual engagement survey among our employees. In
2013 approximately 37,000 employees in more than 70 countries gave
their views on a wide range of business topics and to identify areas where
we can improve.
We measure how engaged our employees are with our strategic priorities.
The group priorities index is derived from 12 questions about employee
perceptions of BP as a company and how it is managed in terms of
leadership and standards. We saw continued improvement in 2013 with a
score of 72% (2012 71%, 2011 67%).
Business leadership teams review the results of the survey and agree
actions to address identified issues. In 2013, safety scores remained
strong and there was an increase in employees’ understanding of the
operating management system, an area of focus identified in the previous
year. While the survey showed an increase in employee confidence in
BP’s leadership, work is needed to further strengthen this.
Global business services (GBS) supports BP’s business processes across
the globe. Here, members of the family day organizing committee in
Malaysia prepare the registration booth.
48
Share ownership
We encourage employee share ownership. For example, through our
ShareMatch plan, which operates in more than 50 countries, we match
BP shares purchased by our employees. We operate a single company-
wide equity plan, which allows employee participation at different levels
globally and is linked to the company’s performance.
The BP code of conduct
The BP code of conduct sets the standard that all BP employees are
required to work to. It is based on our values and it clarifies the ethics
and compliance expectations for everyone who works at BP. The code
defines what BP expects of its people in key areas such as safety,
workplace behaviour, bribery and corruption and financial integrity.
Employees, contractors or other third parties who have concerns that
laws, regulations or the code of conduct may be breached, can get help
through OpenTalk, a helpline operated by an independent company. The
number of cases raised through OpenTalk in 2013 was 1,121 (2012 1,295,
2011 796). The increase in OpenTalk cases over the past few years is due,
in part, to initiatives to promote our code of conduct and speak up culture.
This is supported by high scores in our employee engagement survey
relating to employee understanding of the importance of speaking up. The
most common issues raised in 2013 related to the people section of the
code. This includes treating people fairly, with dignity and giving everyone
equal opportunity; creating a respectful, harassment-free workplace; and
protecting privacy and confidentiality.
In the US, former district court judge Stanley Sporkin acts as an
ombudsperson. Employees and contractors can contact him confidentially
to report any suspected breach of compliance, ethics or the code of
conduct, including safety concerns.
We take steps to identify and correct areas of non-compliance and take
disciplinary action where appropriate. In 2013, 113 employee dismissals
were reported by BP’s businesses for non-adherence to the code of
conduct or unethical behaviour. This excludes dismissals of staff
employed at our retail service station sites, for incidents such as thefts of
small amounts of money.
Following legal settlements with the US government in 2012, BP agreed
to retain an ethics monitor for a term of up to four years from 2013. The
ethics monitor will review and provide recommendations concerning BP’s
ethics and compliance programme (see page 39).
Policy on political activity
BP has a policy of not participating directly in party political activity as a
group or making any contributions to political candidates, whether in cash
or in kind. Employees’ rights to participate in political activity are governed
by the applicable laws in the countries in which we operate. For example,
in the US, BP supports the operation of the BP employee political action
committee to facilitate employee involvement and to assess whether
contributions comply with the law and are publicly disclosed.
BP Annual Report and Form 20-F 2013 Our management of risk
BP manages, monitors and reports on the principal risks and uncertainties
that can impact our ability to deliver our strategy of meeting the world’s
energy needs responsibly while creating long-term shareholder value;
these risks are described in the Risk factors on page 51.
Our management systems, organizational structures, processes,
standards, code of conduct and behaviours together form a system of
internal control that governs how we conduct the business of BP and
manage associated risks.
BP’s risk management system
BP’s risk management system is designed to be a simple, consistent
and clear framework for managing and reporting risks from the group’s
operations to the board. The system seeks to avoid incidents and maximize
business outcomes by allowing us to:
BP’s group risk team analyses the group’s risk profile and maintains
the group risk management system. Our group audit team provides
independent assurance to the group chief executive and board, through
its committees, over whether the group’s system of internal control is
adequately designed and operating effectively to respond appropriately
to the risks that are significant to BP.
Risk governance and oversight
Key risk governance and oversight committees include the following:
Executive committees
Executive team meeting – for strategic and commercial risks.
Group operations risk committee – for health, safety, security,
environment and operations integrity risks.
Group financial risk committee – for finance, treasury, trading and
cyber risks.
Group disclosure committee – for financial reporting risks.
• Understand the risk environment, and assess the specific risks and
Group people committee – for employee risks.
potential exposure for BP.
Resource commitment meeting – for risks related to
• Determine how best to deal with these risks to manage overall
investment decisions.
potential exposure.
• Manage the identified risks in appropriate ways.
Group ethics and compliance committee – for risks associated
with legal and regulatory compliance and ethics.
• Monitor and seek assurance of the effectiveness of the management
of these risks and intervene for improvement where necessary.
Board and its committees
• Report up the management chain to the board on a periodic basis
about how risks are being managed, monitored, assured and the
improvements that are being made.
BP board.
Audit committee.
Our risk management activities
Day-to-day risk
management
Identify, manage
and report risks
Business and
strategic risk
management
Plan, manage
performance
and assure
Oversight and
governance
Set policy
and monitor
material risks
Facilities,
assets and
operations
Business
segments
and functions
Executive
and corporate
functions
Board
Day-to-day risk management – management and staff at our facilities,
assets and functions identify and manage risk, promoting safe, compliant
and reliable operations. For example, our group-wide operating
management system (OMS) integrates BP requirements on health, safety,
security, environment, social responsibility, operational reliability and
related issues. These BP requirements, along with business needs and the
applicable legal and regulatory requirements, underpin the practical plans
developed to help reduce risk and deliver strong, sustainable performance.
Business and strategic risk management – our businesses and
functions integrate risk into key business processes such as strategy,
planning, performance management, resource and capital allocation, and
project appraisal. We do this by collating risk data, assessing risk
management activities, making further improvements and planning new
activities. By using a standardized risk management report, we aim for a
consistent view of risks across BP.
Oversight and governance – the board, executive and functional
leadership provide oversight to identify and understand significant risks to
BP. They also put in place systems of risk management, compliance and
control to mitigate these risks. Executive committees set policy and
oversee the management of group risks, and dedicated board committees
review and monitor certain risks throughout the year.
Safety, ethics and environment assurance committee.
Gulf of Mexico committee.
Board committees
For information on the board and its committees see page 71.
Our risk profile
The nature of our business operations is long term, resulting in many of
our identified risks being enduring in nature. Nonetheless, risks can
develop and evolve over time and their potential impact or likelihood may
vary in response to internal and external events.
As part of BP’s annual planning process, we review the principal risks and
uncertainties to the group. We identify those as having a high priority for
particular oversight by the board and its various committees in the coming
year; the risks identified for particular review in 2014 are listed below.
These may be updated throughout the year in response to changes in
internal and external circumstances. The oversight and management of the
other risks is undertaken in the normal course of business – throughout the
business and in executive and board committees.
Further details of the principal risks and uncertainties we face are set out in
the Risk factors on page 51. There can be no guarantee that our risk
management activities will mitigate or prevent these, or other, risks
from occurring.
Gulf of Mexico oil spill
There is a wide range of risks arising out of the Gulf of Mexico accident and
oil spill. These include legal, operational, reputational and compliance risks.
BP’s management and mitigation of these risks is overseen by the board’s
Gulf of Mexico committee, which seeks to ensure that BP fulfils all
legitimate obligations whilst protecting and defending BP’s interests.
49
Strategic reportBP Annual Report and Form 20-F 2013
Safety and operational risks
Process safety, personal safety and environmental risks
The nature of the group’s operations exposes us to a wide range of significant
health, safety and environmental risks such as incidents associated with
releases of hydrocarbons when drilling wells, operating facilities and
transporting hydrocarbons. We apply our operating management system
(OMS), including group and engineering technical practices as applicable, to
address these risks. See page 41 for more information on safety and our
OMS. Activities include inspection, maintenance, testing, business continuity
and crisis response planning, and competency development for our
employees and contractors. In addition, we conduct our drilling activity through
a global wells organization in order to promote a consistent approach for
designing, constructing and managing wells.
Security
Hostile acts such as terrorism or piracy could harm our people and disrupt
our operations. We monitor for emerging threats and vulnerabilities to manage
our physical and digital security. Physical security threats tend to vary
geographically and by type of business. Our central security team provides
guidance and support to a network of regional security advisers who advise
and conduct assurance with respect to the management of security risks
affecting our people and operations. We also maintain disaster recovery, crisis
and business continuity management plans.
The committee’s responsibilities include oversight and review of the
following activities: the legal strategy for litigation; investigations and
suspension and debarment actions arising from the accident and oil spill;
the strategy connected with settlements and claims; the environmental
work to remediate or mitigate the effects of the oil spill; management
strategy and actions to restore the group’s reputation in the US; and
compliance with government settlement agreements arising out of the
accident and oil spill.
See Legal proceedings page 257 and Gulf of Mexico committee page 78
for further information.
Strategic and commercial risks
10-point plan
In 2011 we set out a 10-point plan to address our priorities through 2014.
Among other things, the plan aims to focus on safety and risk management,
efficient investments and disposals, successful delivery of operating
cashflows, renewal and repositioning of our portfolio, and delivery of our major
projects to plan. We conduct regular planning and performance monitoring
activity as part of managing the risks to delivery of this plan. For an update on
our progress against the plan see page 22.
Geopolitical
The diverse locations of our operations around the world expose us to
a wide range of political developments and consequent changes to the
economic and operating environment. Geopolitical risk is inherent to
many regions in which we operate; heightened political or social tensions or
changes in key relationships could adversely affect the group. We seek to
manage this risk actively through the development and maintenance of
relationships with governments and stakeholders in each country and region.
In addition, we closely monitor events (such as the situation that arose in the
Ukraine in February 2014) and implement risk mitigation plans where
appropriate.
Cybersecurity
The threats to the security of our digital infrastructure continue to evolve and,
like many other global organizations, our reliance on computers and network
technology is increasing. A cybersecurity breach could have a significant
impact on business operations. We seek to manage this risk through
cybersecurity standards, ongoing monitoring of threats, close co-operation
with authorities and awareness initiatives throughout the company. We also
maintain disaster recovery, crisis and business continuity management plans.
Compliance and control risks
Ethical misconduct and legal or regulatory non-compliance
Ethical misconduct or breaches of applicable laws or regulations could damage
our reputation, adversely affect operational results and shareholder value, and
potentially affect our licence to operate. Our code of conduct and our values
and behaviours, applicable to all employees, are central to managing this risk.
Additionally, we have various group requirements covering areas such as
anti-bribery and corruption, anti-money laundering, competition/anti-trust law
and trade sanctions. We keep abreast of new regulations and legislation and
plan our response to them. We also operate a range of compliance training and
monitoring programmes for our employees. We offer an independent
confidential helpline, OpenTalk, for employees, contractors and other third
parties. For information on our code of conduct, see page 48.
Under the terms of the US Department of Justice settlement (see Legal
proceedings on page 257), an ethics monitor will also review and provide
recommendations concerning BP’s ethics and compliance programme.
Trading non-compliance
In the normal course of business, we are subject to risks around our trading
activities which could arise from shortcomings or failures in our systems, risk
management methodology, internal control processes or employees. We have
specific operating standards and control processes to address these risks,
including guidelines in relation to trading, and we seek to monitor compliance
through our dedicated compliance teams. We also seek to maintain a positive
and collaborative relationship with regulators and the industry at large.
50
BP Annual Report and Form 20-F 2013 Risk factors
We urge you to consider carefully the risks described below. The potential
impact of the occurrence, or recurrence, of any of the risks described
below could have a material adverse effect on BP’s business, financial
position, results of operations, competitive position, cash flows, prospects,
liquidity, shareholder returns and/or implementation of its strategic agenda,
including the 10-point plan.
The risks are categorized against the following areas: strategic and
commercial; compliance and control; and safety and operational. In
addition, we have set out one separate risk for your attention – the risk
resulting from the 2010 Gulf of Mexico oil spill.
Gulf of Mexico oil spill
The spill has had and could continue to have a material adverse impact
on BP.
There is significant uncertainty regarding the extent and timing of the
remaining costs and liabilities relating to the 2010 Gulf of Mexico oil spill
(the Incident), the impact of the Incident on our reputation and the resulting
possible impact on our licence to operate including our ability to access
new opportunities. The amount of claims, fines and penalties that become
payable by BP (including as a result of any potential determination of BP’s
negligence or gross negligence), the outcome of litigation, the terms of any
further settlements including the amount and timing of any payments
thereunder, and any costs arising from any longer-term environmental
consequences of the Incident, will also impact upon the ultimate cost for
BP. These uncertainties are likely to continue for a significant period and
may cause our costs to increase materially. Thus, the Incident has had, and
could continue to have, a material adverse impact on the group’s business,
competitive position, financial performance, cash flows, prospects,
liquidity, shareholder returns and/or implementation of its strategic agenda,
particularly in the US. The risks associated with the Incident could also
heighten the impact of the other risks to which the group is exposed as
further described below. See, in particular, Access and renewal; Liquidity,
financial capacity and financial, including credit, exposure; Insurance; US
government settlements and debarment; Regulatory; Liabilities and
provisions; Reporting; and Process safety, personal safety and
environmental risks below.
Strategic and commercial risks
Access and renewal – BP’s future hydrocarbon production depends on
our ability to renew and reposition our portfolio. Increasing competition for
access to investment opportunities and the effects of the Incident on our
reputation and cash flows could result in decreased access to
opportunities globally.
Successful execution of our group strategy depends on implementing
activities to renew and reposition our portfolio. The challenges to renewal
of our upstream portfolio are growing due to increasing competition for
access to opportunities globally among both national and international oil
companies, and heightened political and economic risks in certain
countries where significant hydrocarbon basins are located. Lack of
material positions could impact our future hydrocarbon production.
Moreover, the Incident has affected BP’s reputation, which may have a
long-term impact on the group’s ability to access new opportunities, both
in the US and elsewhere. Adverse public, political, regulatory and industry
sentiment towards BP, and towards oil and gas drilling activities generally,
could damage or impair our existing commercial relationships with
counterparties, partners and host governments and could impair our
access to new investment opportunities, exploration properties,
operatorships or other essential commercial arrangements with potential
partners and host governments, particularly in the US. In addition, costs
and liabilities relating to the Incident have placed, and will continue to
place, a significant burden on our cash flow, which could impede our ability
to invest in new opportunities and deliver long-term growth.
Prices and markets – BP’s financial performance is subject to the
fluctuating prices of crude oil and gas, the volatile prices of refined
products and the profitability of our refining and petrochemicals operations,
as well as exchange rate fluctuations and the general macroeconomic
outlook.
Oil, gas and product prices and margins can be very volatile, and are subject
to international supply and demand. Political developments (including
conflict situations), increased supply from the development of new oil and
gas sources, technological change, global economic conditions and the
influence of OPEC can particularly affect world supply and oil prices.
Previous oil price increases have resulted in increased fiscal take, cost
inflation and more onerous terms for access to resources. As a result,
increased oil prices may not improve margin performance. Decreases in oil,
gas or product prices are likely to have an adverse effect on revenues,
margins and profitability, and a material rapid change, or a sustained
change, in oil, gas or product prices may mean investment or other
decisions need to be reviewed, assets may be impaired, and the viability of
projects may be affected. A prolonged period of low oil prices may impact
our cash flow, profit and ability to maintain our long-term investment
programme with a consequent effect on our growth rate, and may impact
shareholder returns, including dividends and share buybacks, or share price.
Refining profitability can be volatile, with both periodic over-supply and
supply tightness in various regional markets, coupled with fluctuations in
demand. Sectors of the petrochemicals industry are also subject to
fluctuations in supply and demand, with a consequent effect on prices and
profitability.
Crude oil prices are generally set in US dollars, while sales of refined
products may be in a variety of currencies. In addition, a high proportion of
our major project development costs are denominated in local currencies,
which may be subject to volatile fluctuations against the US dollar.
Fluctuations in exchange rates can therefore give rise to foreign exchange
exposures, with a consequent impact on underlying costs and revenues.
Periods of global recession or prolonged instability in financial markets
could negatively impact parties with whom we do or may do business, the
demand for our products and the prices at which they can be sold and
could affect the viability of the markets in which we operate.
Climate change and carbon pricing – climate change and carbon pricing
policies could result in higher costs and reduction in future revenue and
strategic growth opportunities.
Compliance with changes in laws, regulations and obligations relating to
climate change could result in substantial capital expenditure, taxes,
reduced profitability from changes in operating costs, potential restrictions
on the commercial viability of, or our ability to progress, upstream
resources and reserves, and impacts on revenue generation and strategic
growth opportunities. In addition, the changed nature of our participation in
alternative energies could carry reputational, economic and technology
risks.
Geopolitical – the diverse nature of our operations around the world
exposes us to a wide range of political developments and consequent
changes to the operating environment, regulatory environment and law.
We have operations, and are seeking new opportunities, in countries and
regions where political, economic and social transition is taking place.
Some countries have experienced, or may experience in the future,
political instability, changes to the regulatory environment, changes in
taxation, expropriation or nationalization of property, civil strife, strikes, acts
of terrorism, acts of war and insurrections. Any of these conditions
occurring could disrupt or terminate our operations, causing our
development activities to be curtailed or terminated in these areas, or our
production to decline, could limit our ability to pursue new opportunities,
could affect the recoverability of our assets and could cause us to incur
additional costs. See page 4 for information on the locations of our major
areas of operation and activities.
We set ourselves high standards of corporate citizenship and aspire to
contribute to a better quality of life through the products and services we
provide. If it is perceived that we are not respecting or advancing the
economic and social progress of the communities in which we operate or
that we have not satisfactorily addressed all relevant stakeholder concerns
51
Strategic reportBP Annual Report and Form 20-F 2013 in respect of our operations, our reputation and shareholder value could be
damaged and development opportunities may be precluded.
Competition – BP’s group strategy depends upon continuous innovation
and efficiency in a highly competitive market.
The oil, gas and petrochemicals industries are highly competitive. There is
strong competition, both within the oil and gas industry and with other
industries, in supplying the fuel needs of commerce, industry and the
home. Competition puts pressure on the terms of access to new
opportunities, licence costs and product prices, affects oil products
marketing and requires continuous management focus on improving
efficiency, while ensuring safety and operational risk is not compromised.
The implementation of group strategy requires continued technological
advances and innovation including advances in exploration, production,
refining, petrochemicals manufacturing technology and advances in
technology related to energy usage. Our performance could be impeded
if competitors developed or acquired intellectual property rights to
technology that we require, if our innovation lagged the industry, or if
we fail to adequately protect our company brands and trade marks.
Our competitive position in comparison to our peers could be adversely
affected if competitors offer superior terms for access rights or licences,
if we fail to control our operating costs or manage our margins, or if we fail
to sustain, develop and operate efficiently a high quality portfolio of assets.
Joint and other contractual arrangements – BP may not have full
operational control and may have exposure to counterparty credit risk and
disruptions to our operations and strategic objectives due to the nature of
some of its business relationships.
Many of our major projects and operations are conducted through joint
arrangements or associates and through contracting and sub-contracting
arrangements. These arrangements often involve complex risk allocation,
decision-making processes and indemnification arrangements, and BP has
less control of such activities than we would have if BP had full ownership
and operational control. Our partners may have economic or business
interests or objectives that are inconsistent with, or opposed to, those of
BP and may exercise veto rights to block certain key decisions or actions
that BP believes are in its or the joint arrangement’s or associate’s best
interests, or approve such matters without our consent. Additionally, our
joint arrangement partners or associates or contractual counterparties are
primarily responsible for the adequacy of the human or technical
competencies and capabilities which they bring to bear on the joint project
and, in the event these are found to be lacking, then safety, the
performance of the project and BP’s costs may be adversely affected. Our
joint arrangement partners or associates may not be able to meet their
financial or other obligations to their counterparties or to the relevant
project, potentially threatening the viability of such projects. Furthermore,
should accidents or incidents occur in operations in which BP participates,
whether as operator or otherwise, and where it is held that our sub-
contractors or joint arrangement partners are legally liable to share any
aspects of the cost of responding to such incidents, the financial capacity
of these third parties may prove inadequate to fully indemnify BP against
the costs we incur on behalf of the joint or contractual arrangement.
Should a key sub-contractor, such as a lessor of drilling rigs, no longer be
able to make these assets available to BP, this could result in serious
disruption to our operations. Where BP does not have operational control
of a venture, BP may nonetheless still be pursued by regulators or
claimants in the event of an incident.
Rosneft investment – any future erosion of our relationship with Rosneft
could adversely impact our business, strategic objectives, the level of our
reserves and our reputation.
On 21 March 2013, we completed the sale of our 50% interest in TNK-BP
to Rosneft and the purchase of additional shares in Rosneft. We now own
a total shareholding in Rosneft of 19.75%. To the extent we fail to maintain
a good commercial relationship with Rosneft in the future, or to the extent
that as a non-controlling shareholder in Rosneft we are unable in the future
to exercise significant influence over our investment in Rosneft or other
growth opportunities in Russia, our business and strategic objectives in
Russia and our ability to recognize our share of Rosneft’s reserves may be
adversely impacted.
Investment efficiency – poor investment decisions could negatively
impact our business.
Our organic growth is dependent on creating a portfolio of quality options
and investing in the best options. Ineffective group strategy, investment
selection and/or subsequent execution could lead to loss of opportunity,
loss of value and higher capital expenditure.
Reserves progression – inability to progress upstream resources in a
timely manner could adversely affect our long-term replacement of
reserves and negatively impact our business.
Successful execution of our group strategy depends critically on sustaining
long-term reserves replacement. If upstream resources are not progressed
in a timely and efficient manner due to commercial, technical, regulatory or
other reasons, we will be unable to sustain long-term replacement of
reserves.
Major project delivery – our group plan depends upon successful
delivery of major projects, and failure to deliver major projects successfully
could adversely affect our financial performance.
Successful execution of our group plan depends critically on implementing
the activities to deliver major projects over the plan period. Poor delivery of
or operational challenges at any major project that underpins production or
production growth and/or any other major programme designed to
enhance shareholder value, including maintenance turnaround
programmes, could adversely affect our financial performance and our
operating cash flows.
Digital infrastructure – a breach of our digital security or a failure of our
digital infrastructure could result in serious damage to business operations,
personal injury, damage to assets, harm to the environment, reputational
damage, breaches of regulations, litigation, legal liabilities and reparation
costs.
The reliability and security of our digital infrastructure are critical to
maintaining the availability of our business applications, including the
reliable operation of technology in our various business operations and the
collection and processing of financial and operational data, as well as the
confidentiality of certain third-party information. A breach of our digital
security or failure of our digital infrastructure, due to intentional actions
such as cyber-attacks, negligence or otherwise, could cause serious
damage to business operations and, in some circumstances, could result in
the loss of data or sensitive information, injury to people, loss of control of
or damage to assets, harm to the environment, reputational damage,
breaches of regulations, litigation, legal liabilities and reparation costs.
Crisis management, business continuity and disaster recovery – the
group must be able to respond to and recover quickly and effectively from
any disruption or incident, as failure to do so could adversely affect our
business and operations.
Crisis management and contingency plans are required to respond to, and
to continue or recover operations following, a disruption or an incident.
If we do not respond, or are perceived not to respond, in an appropriate
manner to either an external or internal crisis, our business and operations
could be severely disrupted. Inability to restore or replace critical capacity
to an agreed level within an agreed timeframe would prolong the impact of
any disruption and could severely affect our business and operations.
52
BP Annual Report and Form 20-F 2013 People and capability – successful recruitment, development and
utilization of staff is central to our plans.
Successful recruitment of new staff, employee training, development and
continuing enhancement of skills, in particular technical capabilities such as
petroleum engineers and scientists, are key to implementing our plans.
Inability to develop and retain human capacity and capability, both across
the organization and in specific operating locations, could jeopardize
performance delivery. The group relies on recruiting and retaining
high-quality employees to execute its strategic plans and to operate its
business.
In addition, significant board and management focus continues to be
required in responding to matters related to the Incident. Although BP set
up the Gulf Coast Restoration Organization to manage the group’s
long-term response, other key management personnel will need to
continue to devote substantial attention to addressing the associated
consequences for the group, which may negatively impact our staff’s
capability to address and respond to other operational matters affecting the
group but unrelated to the Incident.
Liquidity, financial capacity and financial, including credit, exposure
– failure to operate within our financial framework could impact our ability
to operate and result in financial loss.
The group seeks to maintain a financial framework to ensure that it is able
to maintain an appropriate level of liquidity and financial capacity, and
commercial credit risk is measured and controlled to determine the group’s
total credit risk. Failure to accurately forecast, manage or maintain
sufficient liquidity and credit to meet our needs (including a failure to
understand and respond to potential liabilities) could impact our ability to
operate and result in a financial loss. Trade and other receivables, including
overdue receivables, may not be recovered whether an impairment
provision has been recognized or not. Inability to determine adequately our
credit exposure could lead to financial loss. Furthermore, a substantial and
unexpected cash call or funding request could disrupt our financial
framework or overwhelm our capacity to meet our obligations.
External events could materially impact the effectiveness of the group’s
financial framework. A credit crisis or significant economic shock affecting
banks and other sectors of the economy could impact the ability of
counterparties to meet their financial obligations to the group. It could also
affect our ability to raise capital to fund growth, to maintain our long-term
investment programme and to meet our obligations, and may impact
shareholder returns, including dividends and share buybacks, or share
price. Decreases in the funded levels of our pension plans may also
increase our pension funding requirements.
In addition, a significant operational incident could result in decreases in
our credit ratings which, together with the assessments published by
analysts, the reputational consequences of any such incident and concerns
about the group’s costs arising from any such incident, ongoing
contingencies, liquidity, financial performance and credit spreads, could
increase the group’s financing costs and limit the group’s access to
financing. The group’s ability to engage in both its trading activities and
non-trading businesses could also be impacted in such circumstances due
to counterparty concerns about the group’s financial and business risk
profile and resulting collateral demands, which could be significant. In
addition, BP may be unable to make a drawdown under certain of its
committed borrowing facilities in the event that we are aware that there
are pending or threatened legal, arbitration or administrative proceedings
which, if determined adversely, might reasonably be expected to have a
material adverse effect on our ability to meet the payment obligations
under any of these facilities. Credit rating downgrades could trigger a
requirement for the company to review its funding arrangements with the
BP pension trustees. Any extended constraints on the group’s ability to
obtain financing and to engage in its trading activities on acceptable terms
(or at all) would put pressure on the group’s liquidity. If such constraints
occur at a time when cash flows from our business operations are
constrained, such as following a significant operational incident, the group
could be required to reduce planned capital expenditures and/or increase
asset disposals in order to provide additional liquidity, as the group did
following the Incident.
See Financial statements – Note 19 for more information on financial
instruments and financial risk factors.
Insurance – The limited capacity of the insurance market and BP’s
insurance strategy could, from time to time, expose the group to material
uninsured losses which could have a material adverse effect on BP’s
financial condition and results of operations.
In the context of the limited capacity of the insurance market, many
significant risks are retained by BP. The group generally restricts its
purchase of insurance to situations where this is required for legal or
contractual reasons. This means that the group could be exposed to
material uninsured losses, which could have a material adverse effect on
its financial condition and results of operations. In particular, these
uninsured costs could arise at a time when BP is facing material costs
arising out of some other event which could put pressure on BP’s liquidity
and cash flows. For example, BP has borne and may continue to bear the
entire burden of its share of any property damage, well control, pollution
clean-up and third-party liability expenses arising out of the Incident.
Compliance and control risks
US government settlements and debarment – our settlement with the
US Department of Justice and the SEC in respect of certain charges
related to the Incident may expose us to further penalties, liabilities and
private litigation, and may impact our operations and adversely affect our
ability to quickly and efficiently access US capital markets.
On 15 November 2012, BP reached an agreement with the US government
to resolve all federal criminal and securities claims arising out of the
Incident and comprising settlements with the US Department of Justice
(DoJ) and the SEC. For a description of the terms of the DoJ and SEC
settlements, see Legal proceedings on page 264. Under the DoJ
settlement, BP has agreed to retain an independent third-party auditor who
will review and report to the probation officer, the DoJ, and BP regarding
BP Exploration & Production’s (BPXP) compliance with the key terms of
the settlement including the completion of safety and environmental
management systems audits, operational oversight enhancements, oil spill
response training and drills and the implementation of best practices. The
DoJ settlement also provides for the appointment of an ethics monitor and
a process safety monitor. See Gulf of Mexico oil spill on page 39. The DoJ
criminal and SEC settlements impose significant compliance and remedial
obligations on BP and its directors, officers and employees. Failure to
comply with the terms of these settlements could result in further
enforcement action by the DoJ and the SEC, expose BP to severe
penalties, financial or otherwise, and subject BP to further private litigation,
each of which could impact our operations and have a material adverse
effect on the group’s business.
The US Environmental Protection Agency (EPA) has temporarily
suspended a number of BP entities from participating in new federal
contracts and subjected BPXP to mandatory debarment at its Houston
headquarters. In addition, the EPA has initiated administrative proceedings
to convert the temporary suspension of these BP entities into discretionary
debarment. On 26 November 2013, the EPA issued a Notice of Continued
Suspensions and Proposed Debarments that continued the suspensions of
the previously suspended BP entities, suspended two new BP entities
(BP Alternative Energy and BP Pipelines (Alaska) Inc.), and proposed
discretionary debarment of all suspended BP entities. Both temporary
suspension and mandatory debarment prevent a company from entering
into new contracts or new leases with the US government that would be
performed at the facility where a Clean Water Act violation occurred. See
Legal proceedings on page 264. BP has a significant amount of operations
in the US. See Upstream on page 25 and Oil and gas disclosures for the
group on page 245. Prolonged suspension or debarment from entering
new federal contracts, or further suspension or debarment proceedings in
the future against BP and/or its subsidiaries as a result of violations of the
terms of the DoJ or SEC settlements or otherwise, could have a material
adverse impact on the group’s operations in the US in the future. In
particular, prolonged suspension or debarment could prevent BP from
accessing and developing material new oil and gas resources located in the
US, or prevent BP from engaging in certain development arrangements
with third parties that are standard in the oil and gas industry, which could
make the development of certain of BP’s existing reserves located in the
US less commercially attractive than if relevant BP entities were not
suspended or debarred.
53
Strategic reportBP Annual Report and Form 20-F 2013 As a result of the SEC settlement, as of 5 February 2013 and for a period of
three years thereafter, we are no longer qualified as a ‘well known
seasoned issuer’ (WKSI) as defined in Rule 405 of the Securities Act of
1933, as amended (Securities Act), and therefore will not be able to take
advantage of the benefits available to a WKSI, including engaging in
delayed or continuous offerings of securities using an automatic shelf
registration statement. In addition, as of the SEC settlement date of
10 December 2012 and for a period of five years thereafter, we are no
longer able to utilize certain registration exemptions provided by the
Securities Act in connection with certain securities offerings. We also may
be denied certain trading authorizations under the rules of the US
Commodities Futures Trading Commission, which may prevent us in the
future from entering certain routine swap transactions for an indefinite
period of time.
Regulatory – BP, and the oil industry in general, face increased regulation
in the US and elsewhere that could increase the cost of regulatory
compliance, affect the adequacy of our provisions and limit our access to
new exploration properties.
The oil industry in general is 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, health and safety controls, controls over the
development and decommissioning of a field (including restrictions on
production) and, possibly, nationalization, expropriation, cancellation or
non-renewal 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, and operates in
certain tax jurisdictions that have a degree of uncertainty relating to the
interpretation of, and changes to, tax law. We remain exposed to changes
in the regulatory and legislative environment, such as new laws and
regulations (whether imposed by international treaty or by national or local
governments in the jurisdictions in which we operate), changes in tax or
royalty regimes, price controls, the imposition of trade or other sanctions,
government actions to cancel or renegotiate contracts or other factors.
Governments are facing greater pressure on public finances, which may
increase their motivation to intervene in the fiscal and regulatory
frameworks of the oil and gas industry and we remain exposed to
increases in amounts payable to governments or government agencies.
Such factors could reduce our profitability from operations in certain
jurisdictions, limit our opportunities for new access, require us to divest or
write-down certain assets or curtail or cease certain operations, or affect
the adequacy of our provisions for pensions, tax, environmental and legal
liabilities. Potential changes to pension or financial market regulation could
also impact funding requirements of the group.
Due to the Incident and remedial provisions contained in or that may result
from the DoJ and SEC settlements and other past events in the US, it is
likely that there will be additional oversight and more stringent regulation of
BP’s oil and gas activities in the US and elsewhere, particularly relating to
environmental, health and safety controls and oversight of drilling
operations, as well as access to new drilling areas. BP may be subjected to
a higher number of citations and/or level of fines imposed in relation to any
alleged breaches of safety or environmental regulations. New regulations
and legislation, the terms of BP’s settlements with US government
authorities and future settlements or litigation outcomes related to the
Incident, and/or evolving practices could increase the cost of compliance,
require changes to our drilling operations, exploration, development and
decommissioning plans, impact our ability to capitalize on our assets and
limit our access to new exploration properties or operatorships, particularly
in the deepwater Gulf of Mexico.
We buy, sell and trade oil and gas products in certain regulated commodity
markets. Failure to respond to changes in or to comply with trading
regulations could result in regulatory action and damage to our reputation.
See page 254 for more information on environmental regulation.
Ethical misconduct and non-compliance – ethical misconduct or
breaches of applicable laws by our businesses or our employees could be
damaging to our reputation and shareholder value.
Incidents of ethical misconduct, non-compliance with the
recommendations of the ethics monitor appointed under the terms of the
DoJ settlement or non-compliance with applicable laws and regulations,
including anti-bribery, anti-corruption and anti-manipulation laws and trade
or other sanctions, could be damaging to our reputation and shareholder
value and could subject us to litigation and regulatory action or penalties
under the terms of the DoJ settlement or otherwise. Multiple events of
non-compliance could call into question the integrity of our operations.
For example, in our trading functions, there is the risk that a determined
individual could operate as a ‘rogue trader’, acting outside BP’s
delegations, controls or code of conduct and in contravention of our values
in pursuit of personal objectives that could be to the detriment of BP and
its shareholders.
For certain legal proceedings involving the group, see Legal proceedings
on page 257. For further information on the risks involved in BP’s trading
activities, see Treasury and trading activities below.
Liabilities and provisions – BP’s potential liabilities resulting from
pending and future claims, lawsuits, settlements and enforcement actions
relating to the Incident, together with the potential cost and burdens of
implementing remedies sought in the various proceedings, have had and
are expected to continue to have a material adverse impact on the group’s
business.
Under the Oil Pollution Act of 1990 (OPA 90), BP Exploration & Production
Inc. and BP Corporation North America are among the parties financially
responsible for the clean-up of the Incident and for certain economic
damages as provided for in OPA 90, as well as certain natural resource
damages associated with the spill and certain costs determined by federal
and state trustees engaged in a joint assessment of such natural resource
damages. BP and certain of its subsidiaries have also been named as
defendants in numerous lawsuits in the US arising out of the Incident,
including actions for personal injury and wrongful death, purported class
actions for commercial or economic injury, actions for breach of contract,
violations of statutes, property and other environmental damage, securities
law claims and various other claims, and additional lawsuits or private
claims arising out of the Incident may be brought in the future.
While significant charges have been recognized in the income statement
since the Incident occurred in 2010, the provisions recognized represent
only the current best estimates of expenditures required to settle certain
present obligations that can be reasonably estimated at the end of the
reporting period, and there are future expenditures for which it is not
possible to measure our obligations reliably. BP’s total potential liabilities
resulting from pending and future claims, lawsuits, settlements and
enforcement actions relating to the Incident (including as a result of any
potential determination of BP’s negligence or gross negligence), together
with the potential cost and burdens of implementing remedies sought in
the various proceedings, cannot be fully estimated at this time and are
subject to significant uncertainty but they have had, and are expected to
continue to have, a material adverse impact on the group’s business.
See Financial statements – Note 2 and Legal proceedings on page 257.
Reporting – failure to accurately report our data could lead to regulatory
action, legal liability and reputational damage.
External reporting of financial and non-financial data is reliant on the
integrity of systems and people. Failure to report data accurately and in
compliance with external standards could result in regulatory action, legal
liability and damage to our reputation.
As of the date of the SEC settlement, 10 December 2012, and for a period
of three years thereafter, we are unable to rely on the safe harbor
provisions regarding forward-looking statements provided by the
regulations issued under the Securities Act, and the Securities Exchange
Act of 1934, as amended. Our inability to rely on these safe harbor
provisions may expose us to future litigation and liabilities in connection
with forward-looking statements in our public disclosures.
54
BP Annual Report and Form 20-F 2013 Treasury and trading activities – control of these activities depends on
our ability to process, manage and monitor a large number of transactions.
Failure to do this effectively could lead to business disruption, financial
loss, regulatory intervention or damage to our reputation.
In the normal course of business, we are subject to operational risk around
our treasury and trading activities. Control of these activities is highly
dependent on our ability to process, manage and monitor a large number
of complex transactions across many markets and currencies.
Shortcomings or failures in our systems, risk management methodology,
internal control processes or people could lead to disruption of our
business, financial loss, regulatory intervention or damage to our
reputation. See Legal proceedings on page 257.
Safety and operational risks
The risks inherent in our operations include a number of hazards that,
although many may have a low probability of occurrence, can have
extremely serious consequences if they do occur, such as the Gulf of
Mexico oil spill. The occurrence of any such risks could have a consequent
material adverse impact on the group’s business, competitive position,
cash flows, results of operations, financial position, prospects, liquidity,
shareholder returns and/or implementation of the group’s strategic goals.
Process safety, personal safety and environmental risks – the nature
of our operations exposes us to a wide range of significant health, safety,
security and environmental risks, the occurrence of which could result in
regulatory action, legal liability and increased costs and damage to our
reputation.
The nature of the group’s operations exposes us to a wide range of
significant health, safety, security and environmental risks. The scope of
these risks is influenced by the geographic range, operational diversity and
technical complexity of our activities. In addition, in many of our major
projects and operations, risk allocation and management is shared with
third parties such as contractors, sub-contractors, joint arrangement
partners and associates. See Strategic and commercial risks – Joint and
other contractual arrangements above.
There are risks of technical integrity failure as well as risk of natural
disasters and other adverse conditions in many of the areas in which we
operate, which could lead to loss of containment of hydrocarbons and
other hazardous material, as well as the risk of fires, explosions or other
incidents. In addition, inability to provide safe environments for our
workforce and the public while at our facilities or premises could lead to
injuries or loss of life and could result in regulatory action, legal liability and
damage to our reputation.
Our operations are often conducted in hazardous, remote or
environmentally sensitive locations, in which the consequences of a spill,
explosion, fire or other incident could be greater than in other locations.
These operations are subject to various environmental and safety laws,
regulations and permits and the consequences of failure to comply with
these requirements can include remediation obligations, penalties, loss of
operating permits and other sanctions. Accordingly, inherent in our
operations is the risk that if we fail to abide by environmental and safety
and protection standards, such failure could lead to damage to the
environment and could result in regulatory action, legal liability, material
costs, damage to our reputation or denial of our licence to operate.
BP’s group-wide operating management system (OMS) addresses health,
safety, security, environmental and operations risks, and aims to provide a
consistent framework within which the group can analyse the performance
of its activities and identify and remediate shortfalls. There can be no
assurance that OMS will adequately identify all process safety, personal
safety and environmental risk or provide the correct mitigations, or that all
operations will be in conformance with OMS at all times.
Under the terms of the DoJ settlement (see Legal proceedings on
page 264), a process safety monitor will review, evaluate, and provide
recommendations concerning BPXP’s process safety and risk
management procedures for deepwater drilling in the Gulf of Mexico.
Incidents of non-compliance with the recommendations of the process
safety monitor could be damaging to our reputation and shareholder value
and could subject us to further regulatory action or penalties under the
terms of the DoJ settlement. Multiple events of non-compliance could call
into question the integrity of our operations.
Security – hostile acts against our staff and activities could cause harm to
people and disrupt our operations.
Security threats require continuous oversight and control. Acts of terrorism,
piracy, sabotage, cyber-attacks and similar activities directed against our
operations and facilities, pipelines, transportation or computer systems
could cause harm to people and could severely disrupt business and
operations. Our business activities could also be severely disrupted by,
among other things, conflict, civil strife or political unrest in areas where
we operate.
Product quality – failure to meet product quality standards could lead to
harm to people and the environment and loss of customers.
Supplying customers with on-specification products is critical to
maintaining our licence to operate and our reputation in the marketplace.
Failure to meet product quality standards throughout the value chain could
lead to harm to people and the environment and loss of customers.
Drilling and production – these activities require high levels of
investment and are subject to natural hazards and other uncertainties.
Activities in challenging environments heighten many of the drilling and
production risks including those of integrity failures, which could lead to
curtailment, delay or cancellation of drilling operations, or inadequate
returns from exploration expenditure.
Exploration and production require high levels of investment and are
subject to natural hazards and other uncertainties, including those relating
to the physical characteristics of an oil or natural gas field. Our exploration
and production activities are often conducted in extremely challenging
environments, which heighten the risks of technical integrity failure and
natural disasters discussed above. The cost of drilling, completing or
operating wells is often uncertain. We may be required to curtail, delay or
cancel drilling operations because of a variety of factors, including
unexpected drilling conditions, pressure or irregularities in geological
formations, equipment failures or accidents, adverse weather conditions
and compliance with governmental requirements. In addition, exploration
expenditure may not yield adequate returns, for example in the case of
unproductive wells or discoveries that prove uneconomic to develop.
The Gulf of Mexico oil spill illustrates the risks we face in our drilling and
production activities.
Transportation – all modes of transportation of hydrocarbons involve
inherent and significant risks.
All modes of transportation of hydrocarbons involve inherent risks. An
explosion or fire or loss of containment of hydrocarbons or other hazardous
material could occur during transportation by road, rail, sea or pipeline.
This is a significant risk due to the potential impact of a release on people
and the environment and given the high volumes potentially involved.
55
Strategic reportBP Annual Report and Form 20-F 2013 Liquidity and capital
resources
Since the Gulf of Mexico oil spill in 2010 and the significant costs relating
to the response activities and the uncertainty regarding the ultimate
magnitude of its liabilities and timing of cash outflows, the group’s
situation has continued to stabilize. This has been reflected in the group’s
liquidity and capital resources position, which has continued to strengthen
underpinned by a prudent financial framework.
The group’s long-term credit ratings are A (positive outlook) from Standard
& Poor’s, and A2 (stable outlook) from Moody’s Investor Services, both
remaining unchanged during 2013.
We increased our financial flexibility in 2013 with the completion of the
sale of BP’s 50% share in TNK-BP to Rosneft in return for cash and shares.
We received net $11.8 billion cash on completion (in addition to $0.7 billion
already received as a dividend in December 2012), as well as increasing our
shareholding in Rosneft from 1.25% to 19.75%.
Financial framework
We continue to refine our financial framework to support the pursuit
of value growth for shareholders, while maintaining a secure financial
base. BP intends to increase operating cash flowa by around 50% in
2014 compared with 2011b, and thereafter maintain focus on growing
sustainable free cash flowc. We expect that the improvement in operating
cash flow will be delivered partly from the completion of the Deepwater
Horizon Oil Spill Trust fund payments, and partly through high-margin
projects coming onstream. Any growth in operating cash flow will be
available to increase both organic capital expenditure and shareholder
distributions.
The financial framework remains prudent and we expect to operate
within a gearingd range of 10-20%, and to be robust to cash break-even
levels in an oil price environment between $80 and $100 per barrel. We
expect to continue to maintain a significant liquidity buffer while
uncertainties remain.
Dividends and other distributions to shareholders
We are committed to maintaining a progressive and sustainable dividend
policy through our focus on increasing sustainable free cash flows.
Since resuming dividend payments in 2011, we have steadily increased the
dividend. From the quarterly dividend of 7 cents per share paid in 2011 it
has increased by 36% to 9.5 cents per share paid in the fourth quarter of
2013. Going forward, the board will review the dividend level with the first
and third quarter results each year.
The total dividend paid in cash to BP shareholders in 2013 was $5.4 billion
with shareholders also having the option to receive a scrip dividend (2012
$5.3 billion cash). The dividend is determined in US dollars, the economic
currency of BP.
During 2013 we started to buy back shares as part of an $8-billion share
repurchase programme, fulfilling a commitment to offset any dilution to
earnings per share from the Rosneft transaction. The total cash paid for
share buybacks in 2013 was $5.5 billion (2012 nil). Details of share
repurchases to satisfy the requirements of certain employee share-based
payment plans are set out on page 278.
a Operating cash flow is net cash provided by operating activities, as presented in the group cash
flow statement on page 125.
b Assuming an oil price of $100 per barrel and a Henry Hub gas price of $5/mmBtu in 2014. The
projection assumes BP’s estimate of a Rosneft dividend. 2011 excludes BP’s share of TNK-BP
dividends. The projection includes BP’s payment commitments under the Department of Justice
and SEC settlements. It does not reflect any cash flows relating to other liabilities, contingent
liabilities, settlements or contingent assets arising from the Gulf of Mexico oil spill which may or
may not arise at that time. We are not able to reliably estimate the amount or timing of a number
of contingent liabilities. See Financial statements – Note 2 for further information.
c Free cash flow is operating cash flow less net cash used in investing activities, as presented in
the group cash flow statement on page 125.
d Gearing refers to the ratio of the group’s net debt to net debt plus equity and is a non-GAAP
measure. See Financial statements – Note 28 for information on gross debt, which is the nearest
equivalent measure to net debt on an IFRS basis.
56
Financing the group’s activities
The group’s principal commodity, oil, is priced internationally in US dollars.
Group policy has generally been to minimize economic exposure to
currency movements by financing operations with US dollar debt. Where
debt is issued in other currencies, including euros, it is generally swapped
back to US dollars using derivative contracts, or else hedged by maintaining
offsetting cash positions in the same currency. The cash balances of the
group are mainly held in US dollars or swapped to US dollars and holdings
are well-diversified to reduce concentration risk. The group is not therefore
exposed to significant currency risk regarding its borrowings. Also see Risk
factors on page 51 for further information on risks associated with prices
and markets and Financial statements – Note 19.
The group’s finance debt at 31 December 2013 amounted to $48.2 billion
(2012 $48.8 billion). Of the total finance debt, $7.4 billion is classified as
short term at the end of 2013 (2012 $10.0 billion). The short-term balance
includes $6.2 billion for amounts repayable within the next 12 months
relating to long-term borrowings (2012 $6.2 billion). Commercial paper
markets in the US and Europe are a further source of short-term liquidity
for the group to provide timing flexibility. At 31 December 2013,
outstanding commercial paper amounted to $1.0 billion (2012 $3.0 billion).
We have a European Debt Issuance Programme (DIP) in place under which
the group may raise up to $30 billion of debt for maturities of one month or
longer. At 31 December 2013, the amount drawn down against the DIP
was $13.9 billion (2012 $14.0 billion). Since 5 February 2013 the group has
had a US shelf registration statement with a limit of $30 billion. This was
converted from an unlimited shelf registration following the approval in
December 2012 of the SEC settlement in respect of Deepwater Horizon-
related claims. At 31 December 2013 $6.9 billion had been drawn down
since conversion. In addition, the group has an Australian Note Issuance
Programme of $5 billion Australian dollars, and as at 31 December 2013
the amount drawn down was $0.8 billion Australian dollars (2012
A$0.5 billion).
None of the capital market bond issuances since the Gulf of Mexico oil spill
contain any additional financial covenants compared with the group’s
capital markets issuances prior to the incident.
BP accessed international capital markets throughout the year using its US,
European and Australian issuance programmes, with bond issuances
amounting to $8.6 billion in 2013.
The maturity profile and fixed/floating rate characteristics of the group’s
debt are described in Financial statements – Note 19.
Net debt was $25.2 billion at the end of 2013, a reduction of $2.3 billion
from the 2012 year-end position of $27.5 billion. The ratio of net debt to net
debt plus equity was 16.2% at the end of 2013 (2012 18.7%). Net debt and
the ratio of net debt to net debt plus equity are non-GAAP measures.
We believe that these measures provide useful information to investors.
Net debt enables investors to see the economic effect of gross debt,
related hedges and cash and cash equivalents in total. The net debt ratio
enables investors to see how significant net debt is relative to equity from
shareholders. See Financial statements – Note 28 for gross debt, which
is the nearest equivalent measure on an IFRS basis, and for further
information on net debt.
Cash and cash equivalents of $22.5 billion at 31 December 2013 (2012
$19.6 billion) are included in net debt. We manage our cash position to
ensure the group has adequate cover to respond to potential short-term
market illiquidity, and expect to maintain a strong cash position. Cash
balances are pooled centrally where permissible, and deployed globally
as required. Cash surpluses are deposited with creditworthy banks or
invested in high grade commercial paper and money market funds with
short maturities to ensure availability. The group holds $2 billion of cash
outside the UK and it is not expected that any significant tax will arise on
repatriation. Further information on the management of liquidity risk and
credit risk is provided in Financial statements – Note 19, and on the cash
position in Financial statements – Note 23.
BP Annual Report and Form 20-F 2013 The group also has access to significant sources of liquidity in the form of
committed bank facilities. We renegotiated our committed bank facilities
during 2013, putting in place borrowing facilities of $7.4 billion (2012
$6.8 billion) with 26 international banking counterparties, of which
$7.0 billion is available to draw and repay over a term of five years and
$0.4 billion is available to draw and repay over a term of three years. In
addition, the group continued to strengthen its access to commercial bank
letters of credit (LC) and at the end of 2013 had in place committed
LC facilities of $7.5 billion and secured LC arrangements of $2.4 billion, to
supplement its uncommitted and unsecured LC lines.
We believe that the group has sufficient working capital for foreseeable
requirements, taking into account the amounts of undrawn borrowing
facilities and increased levels of cash and cash equivalents, and the
ongoing ability to generate cash.
Uncertainty remains regarding the amount and timing of future
expenditures relating to the Gulf of Mexico oil spill and the implications
for future activities. See Risk factors on page 51 and Financial statements
– Note 2 for further information.
Off-balance sheet arrangements
At 31 December 2013, the group’s share of third-party finance debt of
equity-accounted entities was $17,008 million (2012 $6,884 million). These
amounts are not reflected in the group’s debt on the balance sheet. The
group has issued third-party guarantees under which amounts outstanding
at 31 December 2013 were $199 million (2012 $237 million) in respect of
liabilities of joint ventures and associates and $648 million (2012 $713
million) in respect of liabilities of other third parties. Of these amounts,
$115 million (2012 $166 million) of the joint ventures and associates
guarantees relate to borrowings and for other third-party guarantees, $487
million (2012 $543 million) relates to guarantees of borrowings. Details of
operating lease commitments, which are not recognized on the balance
sheet, are shown in the table on page 252 and provided in Financial
statements – Note 9.
Contractual obligations
The following table summarizes the group’s contractual obligations, capital
expenditure commitments for property, plant and equipment at
31 December 2013 and the proportion of that expenditure for which
contracts have been placed.
Expected payments by period
2014
2015
2016
2017
2018
2019 and thereafter
Total
$ million
Capital expenditure
Contractual
obligationsa
134,075
40,471
29,279
23,186
20,360
105,377
352,748
Committed
17,973
9,010
5,703
4,021
2,292
3,443
42,442
of which is
contracted
8,676
2,581
1,321
685
189
253
13,705
a Including $100,805 million for which a liability is recognized on the balance sheet.
The group’s principal contractual obligations and a description of the
nature of the group’s unconditional purchase obligations are provided on
page 252.
Capital expenditure is considered to be committed when the project has
received the appropriate level of internal management approval. For joint
operations, the net BP share is included in the amounts above.
In addition, at 31 December 2013, the group had committed to capital
expenditure relating to investments in equity-accounted entities amounting
to $1,458 million. Contracts were in place for $161 million of this total.
Cash flow
The following table summarizes the group’s cash flows.
Net cash provided by operating
activities
Net cash used in investing activities
Net cash provided by (used in)
2013
2012
$ million
2011
21,100
(7,855)
20,479
(13,075)
22,218
(26,753)
financing activities
(10,400)
(2,010)
477
Currency translation differences
relating to cash and cash
equivalents
Increase (decrease) in cash and cash
equivalents
Cash and cash equivalents at
40
64
(493)
2,885
5,458
(4,551)
beginning of year
19,635
14,177
18,728
Cash and cash equivalents at end
of year
22,520
19,635
14,177
Net cash provided by operating activities for the year ended 31 December
2013 was $21,100 million compared with $20,479 million for 2012. The
cash outflow in respect of the Gulf of Mexico oil spill reduced from $2,382
million in 2012 to $73 million in 2013. Excluding the impacts of the Gulf of
Mexico oil spill, net cash provided by operating activities was $21,173
million for 2013, compared with $22,861 million for 2012, a decrease of
$1,688 million. Profit before taxation excluding the impact of the Gulf of
Mexico oil spill increased by $7,545 million, of which $9,163 million related
to the non-cash impacts of higher depreciation, impairments and gains and
losses on disposal offset by lower earnings from joint ventures and
associates. An increase in working capital requirements of $3,920 million
was largely offset by lower income taxes paid.
Net cash provided by operating activities for the year ended 31 December
2012 was $20,479 million compared with $22,218 million for 2011. The
cash outflow in respect of the Gulf of Mexico oil spill reduced from $6,813
million in 2011 to $2,382 million in 2012. Excluding the impacts of the Gulf
of Mexico oil spill, net cash provided by operating activities was $22,861
million for 2012, compared with $29,031 million for 2011, a decrease of
$6,170 million. Profit before taxation excluding the impacts of the Gulf of
Mexico oil spill decreased by $11,341 million, of which $4,730 million
related to the non-cash impacts of higher depreciation, impairments and
gains and losses on disposal and lower equity-accounted earnings of joint
ventures and associates. A reduction in working capital requirements of
$3,667 million was largely offset by lower dividends received from joint
ventures and associates, principally TNK-BP.
Net cash used in investing activities was $7,855 million in 2013 (2012
$13,075 million and 2011 $26,753 million). The decrease in cash used in
2013 reflected an increase in disposal proceeds of $10,401 million, partly
offset by an increase in our investments in equity-accounted entities,
mainly relating to the completion of the sale of our interest in TNK-BP and
subsequent investment in Rosneft. There was also an increase in our other
capital expenditure excluding acquisitions of $1,298 million. The decrease
in cash used in 2012 reflected an absence of significant expenditure on
business combinations compared with 2011 when we spent $10,909
million, mainly for the Reliance and Devon acquisitions, as well as an
increase in disposal proceeds of $8,757 million. This was partially offset by
an increase in capital expenditure excluding acquisitions of $5,914 million.
The group has had significant levels of capital investment for many years.
Cash flow in respect of capital investment, excluding acquisitions, was
$30 billion in 2013 (2012 $24.8 billion and 2011 $18.9 billion). Sources of
funding are fungible, but the majority of the group’s funding requirements
for new investment come from cash generated by existing operations.
57
Strategic reportBP Annual Report and Form 20-F 2013
Acquisitions and disposals
There were no significant acquisitions in 2013 and 2012.
In 2011, we acquired a 30% interest in each of 21 oil and gas production-
sharing agreements operated by Reliance Industries Limited in India for
$7.0 billion. We also completed the purchase, for $3.6 billion, of 10
exploration and production blocks in Brazil, which was the final part of a
$7-billion transaction with Devon Energy that had been announced in
March 2010.
During 2013 BP completed sale and purchase agreements for the sale of
BP’s 50% interest in TNK-BP to Rosneft, and for BP’s further investment in
Rosneft. For more information on this transaction see Financial statements
– Note 6.
Total cash disposal proceeds received during 2013 were $22 billion. This
included $16.7 billion for the disposal of BP’s interest in TNK-BP, $1.4
billion for the disposal of our Texas City refinery and a portion of its retail
and logistics network in the south-eastern US to Marathon Petroleum
Corporation and $2.2 billion for the sale of the Carson refinery in California,
and related assets in the region to Tesoro Corporation. We also completed
the sale of our interests in a number of central North Sea oil and gas fields
to TAQA.
Total disposal proceeds received during 2012 were $11.6 billion. This
included $5.55 billion for the disposal of BP’s interests in the Marlin hub,
Horn Mountain, Holstein, Ram Powell and Diana Hoover fields in the Gulf
of Mexico, $1.5 billion for the sale of the Canadian natural gas liquids (NGL)
business to Plains Midstream Canada ULC and $1.025 billion for the sale of
BP’s interest in the Jonah and Pinedale upstream operations in Wyoming,
to LINN Energy, LLC.
Total disposal proceeds received during 2011, after the repayment of
the disposal deposit relating to Pan American Energy LLC (PAE), were
$2.8 billion.
See Financial statements – Note 3 and Note 4 for further details
of business combinations and non-current assets held for sale.
Net cash used in financing activities was $10,400 million in 2013 (2012
$2,010 million and 2011 $477 million net cash provided by financing
activities). The increase in net cash used in 2013 primarily reflected the
buyback of shares of $5.5 billion as part of our $8-billion share repurchase
programme, lower net proceeds of $1,055 million from long-term financing
and an increase in the net repayment of short-term debt of $1,353 million.
The increase in net cash used in 2012 primarily reflected a net decrease in
short-term debt of $2,888 million and an increase in dividends paid of
$1,222 million, partly offset by an increase in net proceeds from long-term
financing of $1,412 million.
During the period 2011 to 2013, our total sources of cash amounted to
$101 billion, and our total uses of cash amounted to $106 billion. The
increase in cash and cash equivalents held of $4 billion was financed by an
increase in finance debt of $9 billion over the three-year period. During this
period, the price of Brent crude oil has averaged $110.53 per barrel.
Sources and uses of cash over the three-year period as a whole, are
analysed in the table below.
Sources of cash:
Net cash provided by operating activities
Disposals
Uses of cash:
Capital expenditure
Acquisitions
Net repurchase of shares
Dividends paid to BP shareholders
Dividends paid to non-controlling interests
Net use of cash
Increase in finance debt
Increase in cash and cash equivalents
$ billion
64
37
101
74
11
5
15
1
106
(5)
9
4
Disposal proceeds received in cash during the three-year period exceeded
cash used for acquisitions, as a result in particular of our ongoing disposal
programme started in 2010 and the disposal of our interest in TNK-BP in
2013. Net investment (capital expenditure and acquisitions less disposal
proceeds) during this period averaged $16 billion per year. Dividends paid
to BP shareholders totalled $15 billion during the three-year period. In the
past three years, $4 billion has been contributed to funded pension plans.
This is reflected in net cash provided by operating activities in the table
above.
58
The Strategic report was approved by the board and signed on its behalf by
David J Jackson, Company Secretary on 6 March 2014.
BP Annual Report and Form 20-F 2013
Corporate
governance
60
Board of directors
66
Executive team
C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
n
c
e
69 Governance overview
71 How the board works
71
71
71
71
71
71
71
72
72
72
Board governance in BP
Role of the board
Board composition
Key roles and responsibilities
Appointment and time commitment
Independence and conflicts of interest
Succession
Board activity
Risk and assurance
International advisory board
72 Board effectiveness
72
73
Induction and board learning
Board evaluation
73 Shareholder engagement
73
73
73
73
Institutional investors
Private investors
AGM
UK Corporate Governance Code compliance
74 Committee reports
74
77
78
79
80
Audit committee
Safety, ethics and environment assurance committee
Gulf of Mexico committee
Nomination committee
Chairman’s committee
81 Directors’ remuneration report
82
84
96
Chairman’s annual statement
2013 annual report on remuneration
Directors’ remuneration policy
109 Regulatory information
Internal Control Revised Guidance for Directors (Turnbull)
110
110 Corporate governance practices
111
111
111
112 Memorandum and Articles of Association
Code of ethics
Controls and procedures
Principal accountants’ fees and services
BP Annual Report and Form 20-F 2013
59
Board of directorsa
As at 6 March 2014
1
5
9
13
2
6
10
14
4
8
12
3
7
11
15
Key to portraits
1 Carl-Henric Svanberg
5 Antony Burgmans
9 Ian Davis
13 Phuthuma Nhleko
2 Bob Dudley
6 Cynthia Carroll
10 Professor Dame Ann Dowling
14 Andrew Shilston
3 Paul Anderson
7 Iain Conn
11 Dr Brian Gilvary
4 Admiral Frank Bowman
8 George David
12 Brendan Nelson
a The ages of the board are correct as at 31 December 2013.
60
BP Annual Report and Form 20-F 2013
Carl-Henric Svanberg
Chairman
Bob Dudley
Group chief executive
Tenure
Appointed to the board 1 September 2009 (4 years)
Tenure
Appointed to the board 6 April 2009 (4 years)
Board and committee activities
Chairman
Chairman of the chairman’s committee
Chairman of the nomination committee
Attends the safety, ethics and environment assurance committee (SEEAC)
Attends the Gulf of Mexico committee
Attends the remuneration committee
Outside interests
Non-executive director of Rosneft
Member of Tsinghua Management University Advisory Board, Beijing, China
Member of BritishAmerican Business International Advisory Board
Member of UAE/UK CEO Forum
Member of Turkish/British CEO Forum
Member of Russian Geographical Society
Outside interests
Chairman of AB Volvo
Age
61
Nationality
Swedish
Age
58
Nationality
American
Career
Bob Dudley became group chief executive on 1 October 2010.
Career
Carl-Henric Svanberg became chairman of the BP board on 1 January
2010.
Bob joined Amoco Corporation in 1979, working in a variety of engineering
and commercial posts. Between 1994 and 1997, he worked on corporate
development in Russia.
He spent his early career at Asea Brown Boveri and the Securitas Group,
before moving to the Assa Abloy Group as president and chief executive
officer.
In 1997, he became general manager for strategy for Amoco and in 1999,
following the merger between BP and Amoco, was appointed to a similar
role in BP.
From 2003 until 31 December 2009, when he left to join BP, he was
president and chief executive officer of Ericsson, also serving as the
chairman of Sony Ericsson Mobile Communications AB. He was a
non-executive director of Ericsson between 2009 and 2012.
He was appointed chairman and a member of the board of AB Volvo on
4 April 2012.
He is a member of the External Advisory Board of the Earth Institute at
Columbia University, a member of the Advisory Board of Harvard Kennedy
School and on the Leadership Council of the United Nations Sustainable
Development Solutions Network. He is also the recipient of the King of
Sweden’s medal for his contribution to Swedish industry.
Relevant experience and skills
Carl-Henric Svanberg’s career in global business, latterly as chief executive
officer of Ericsson, is particularly relevant to BP as has been demonstrated
during his tenure as chairman. In leading the board, he has focused on the
development of the group’s strategy and its communication to
shareholders. He has also concentrated on the work of the nomination
committee in endeavouring to ensure that the board has a strong list of
candidates to secure its stewardship of the company.
Carl-Henric Svanberg’s performance during the year has been evaluated by
the chairman’s committee, led by Antony Burgmans.
Between 1999 and 2000, he was executive assistant to the group chief
executive, subsequently becoming group vice president for BP’s
renewables and alternative energy activities. In 2002, he became group
vice president responsible for BP’s upstream businesses in Russia, the
Caspian region, Angola, Algeria and Egypt.
From 2003 to 2008, he was president and chief executive officer of
TNK-BP in Moscow. On his return to BP in 2009 he was appointed to the
BP board and oversaw the group’s activities in the Americas and Asia.
Between 23 June and 30 September 2010, he served as the president and
chief executive officer of BP’s Gulf Coast Restoration Organization in the
US. He was appointed a director of Rosneft in March 2013 following BP’s
acquisition of a stake in Rosneft.
Relevant experience and skills
Bob Dudley has spent his entire career in the oil and gas industry. His
broad range of roles with Amoco and BP has given him substantial global
experience.
Since his appointment as group chief executive in 2010, Bob has
re-organized the operations of the group and has moved its focus to value
not volume; all without any compromise on safety. During the year he has
successfully completed the disposal of the group’s interest in TNK-BP and
the acquisition of a significant stake in Rosneft.
Bob Dudley’s performance has been considered and evaluated by the
chairman’s committee.
61
Corporate governanceBP Annual Report and Form 20-F 2013 After his retirement as an Admiral in 2004, he was president and chief
executive officer of the Nuclear Energy Institute until 2008. He served on
the BP Independent Safety Review Panel and was a member of the BP
America external advisory council. He was appointed Honorary Knight
Commander of the British Empire in 2005 by Queen Elizabeth II. He was
elected to the US National Academy of Engineering in 2009.
Relevant experience and skills
Frank Bowman has a deep knowledge of engineering coupled with
exceptional experience in process safety arising from his time with the US
Navy and, later, the Nuclear Energy Institute. His service on the BP
Independent Safety Review Panel gave him direct experience of BP’s
safety aims and requirements, which has been important for his work on
the SEEAC. He has made a significant contribution to the work of the Gulf
of Mexico committee.
Antony Burgmans
Independent non-executive director
Tenure
Appointed 5 February 2004 (10 years)
Board and committee activities
Chairman of the remuneration committee
Member of the SEEAC
Member of the chairman’s committee
Member of nomination committee
Outside interests
Member of the supervisory boards of Akzo Nobel N.V., AEGON N.V. and
SHV Holdings N.V.
Chairman of the supervisory board of TNT Express
Age
66
Nationality
Dutch
Career
Antony Burgmans joined Unilever in 1972, holding a succession of
marketing and sales posts, including the chairmanship of PT Unilever
Indonesia from 1988 until 1991.
In 1991, he was appointed to the board of Unilever, becoming business
group president, ice cream and frozen foods, Europe in 1994, and chairman
of Unilever’s Europe committee, co-ordinating its European activities. In
1998, he became vice chairman of Unilever NV and in 1999, chairman of
Unilever NV and vice chairman of Unilever PLC. In 2005, he became
non-executive chairman of Unilever NV and Unilever PLC until his
retirement in 2007. During his career he has lived and worked in London,
Hamburg, Jakarta, Stockholm and Rotterdam.
Antony Burgmans has been nominated chairman of Akzo Nobel’s
supervisory board from April 2014.
Relevant experience and skills
Antony Burgmans’ executive career has been in the fields of international
production, distribution and marketing. Over the years he has made a
significant contribution to the work of the board, adding insight to the areas
of reputation, brand and culture. His global perspective has particular value
as chairman of the remuneration committee and also to his work on the
SEEAC, on whose behalf he has made several visits to operations of the
group.
He led the remuneration committee in its task of preparing a formal
remuneration policy for adoption by shareholders. In this role he has had
extensive dialogue with shareholders. He continues to provide wise
counsel to the board and leads the evaluation of the chairman.
Paul Anderson
Independent non-executive director
Tenure
Appointed 1 February 2010 (4 years)
Board and committee activities
Chairman of the SEEAC
Member of the chairman’s committee
Member of the nomination committee
Member of the Gulf of Mexico committee
Outside interests
Non-executive director of BAE Systems PLC.
Age
68
Nationality
American
Career
Paul Anderson was formerly chief executive at BHP Billiton and Duke
Energy, where he also served as chairman of the board. Having previously
been chief executive officer and managing director of BHP Limited and
then BHP Billiton Limited and BHP Billiton Plc, he rejoined these latter two
boards in 2006 as a non-executive director, retiring on 31 January 2010.
He also served as a non-executive director on a number of boards in the
US and Australia and as chief executive officer of Pan Energy Corp.
Relevant experience and skills
Paul Anderson became a board member in early 2010, joining the SEEAC.
He was a member of the Gulf of Mexico committee from its formation in
August 2010. He took the chair of the SEEAC in December 2012. As chair
he has continued the committee’s focus on safety matters. His broad
experience of the global oil and gas industry and of the US business
environment has benefited the board, the SEEAC and the Gulf of Mexico
committee. He has actively supported the work of the BP Massachusetts
Institute of Technology (MIT) academy.
He has led the SEEAC on several visits to the company’s operations and
has commenced a dialogue with the company’s socially responsible
investors.
Admiral Frank Bowman
Independent non-executive director
Tenure
Appointed 8 November 2010 (3 years)
Board and committee activities
Member of the SEEAC
Member of the chairman’s committee
Member of the Gulf of Mexico committee
Outside interests
President of Strategic Decisions, LLC.
Director of Morgan Stanley Mutual Funds
Director of the American Shipbuilding Suppliers Association
Director of Naval and Nuclear Technologies, LLP.
Age
69
Nationality
American
Career
Frank Bowman joined the United States Navy in 1966. During his naval
service, he commanded the nuclear submarine USS City of Corpus Christi
and the USS Holland. He served as a flag officer: as the Navy’s chief of
personnel; on the joint staff as director of Political-Military Affairs; and as a
director of the naval nuclear propulsion programme in the Department of
the Navy and the Department of Energy for over eight years. He also
completed two masters degrees in engineering at the Massachusetts
Institute of Technology in 1973.
62
BP Annual Report and Form 20-F 2013 At the end of 2000, he returned to London as group vice president and a
member of the Refining and Marketing segment’s executive committee,
taking over responsibility in 2001 for BP’s marketing operations in Europe.
In 2002 he was appointed chief executive of BP Petrochemicals. Following
his appointment to the board in 2004, he served for three years as group
executive officer, strategic resources, with responsibility for a number of
group functions and regions.
Relevant experience and skills
Iain Conn’s career has given him extensive knowledge of a broad range of
BP’s businesses, particularly in the Downstream, which he has led since
2007. In this last period he has successfully remodelled BP’s downstream
business. He has deep knowledge of safety, manufacturing, energy
markets and technology. He has continued to refocus the group’s
downstream operations whilst growing the contribution of that segment.
Iain Conn’s performance has been evaluated by the group chief executive
and considered by the chairman’s committee.
George David
Independent non-executive director
Tenure
Appointed 11 February 2008 (6 years)
Board and committee activities
Member of the audit committee
Member of the remuneration committee
Member of the Gulf of Mexico committee
Member of the chairman’s committee
Outside interests
Vice-Chairman of the Peterson Institute for International Economics
Age
71
Nationality
American
Career
George David began his career in The Boston Consulting Group before
joining the Otis Elevator Company in 1975. He held various roles in Otis
and later in United Technologies Corporation (UTC), following Otis’s merger
with UTC in 1976. In 1992, he became UTC’s chief operating officer. He
served as UTC’s chief executive officer from 1994 until 2008 and as
chairman from 1997 until his retirement in 2009.
Relevant experience and skills
George David has substantial global business and financial experience
through his long career with UTC, a business with significant reliance on
safety and technology. He previously chaired BP’s technology advisory
council and has brought insights from that task to the board.
He is an active member of the audit, remuneration and Gulf of Mexico
committees, bringing a strong US and global view to their deliberations.
Cynthia Carroll
Independent non-executive director
Tenure
Appointed 6 June 2007 (6 years)
Board and committee activities
Member of the SEEAC
Member of the chairman’s committee
Member of nomination committee
Outside interests
Non-executive director of Hitachi Ltd.
Age
57
Nationality
American
Career
Early in her career in 1989, Cynthia Carroll joined Alcan (Aluminum
Company of Canada) and ran a packaging company, led a global bauxite,
alumina and speciality chemicals business and later was president and
chief executive officer of the Primary Metal Group, responsible for
operations in more than 20 countries. In 2007 she became the chief
executive of Anglo American plc, the global mining group, operating in
45 countries with 150,000 employees, and was chairman of Anglo
Platinum Limited and of De Beers s.a. She stepped down from these
roles in April 2013.
Relevant experience and skills
Cynthia Carroll’s leadership of global businesses, particularly in the
extractive industry sector has enabled her to make a strong contribution to
the work of the BP board and the SEEAC. She has been a leader in
working to enhance safety performance in the mining industry, and her
geo-political experience has been valuable during the course of the year,
as has her work on the nomination committee.
She recently visited BP’s operations in Alaska on behalf of the SEEAC.
Iain Conn
Chief executive, Downstream
Tenure
Appointed to the board 1 July 2004 (9 years)
Group responsibilities
Manufacturing, logistics, marketing operations of BP’s fuels,
petrochemicals and lubricants businesses
Group regional responsibility for Europe, southern Africa and Asia
BP brand and related matters
Outside interests
Non-executive director and senior independent director of Rolls-Royce
Holdings plc.
Chairman of the advisory board of Imperial College Business School
Member of the council of Imperial College
Age
51
Nationality
British
Career
Iain Conn was appointed chief executive, Downstream on 1 June 2007.
He joined BP Oil International in 1986, working in a variety of roles in oil
trading, commercial refining and exploration before becoming, on the
merger between BP and Amoco in 1999, vice president of BP Amoco
Exploration’s mid-continent business unit.
63
Corporate governanceBP Annual Report and Form 20-F 2013 Ian Davis
Independent non-executive director
Tenure
Appointed 2 April 2010 (3 years)
Board and committee activities
Chairman of the Gulf of Mexico committee
Member of the remuneration committee
Member of the chairman’s committee
Member of the nomination committee
Outside interests
Chairman of Rolls-Royce Holdings plc.
Non-executive member of the UK Cabinet Office
Non-executive director of Johnson & Johnson, Inc.
Senior adviser to Apax Partners LLP.
Age
62
Nationality
British
Career
Ian Davis spent his early career at Bowater, moving to McKinsey &
Company in 1979. He was managing partner of McKinsey’s practice in the
UK and Ireland from 1996 to 2003. In 2003, he was appointed as chairman
and worldwide managing director of McKinsey, serving in this capacity
until 2009. During his career with McKinsey, he served as a consultant to a
range of global organizations across the private, public and not-for-profit
sectors. He retired as senior partner on 30 July 2010.
Relevant experience and skills
Ian Davis brings significant financial and strategic experience to the board.
He has had a lengthy career working with and advising global organizations
and companies in the oil and gas industry. This experience has been
recognized by the board in his membership of the remuneration committee
and chairmanship of the Gulf of Mexico committee.
As chairman of the Gulf of Mexico committee he has led the board’s
oversight of the response in the Gulf and guided their consideration of the
various legal issues which continue to arise following the Deepwater Horizon
accident.
Professor Dame Ann Dowling
Independent non-executive director
Tenure
Appointed 3 February 2012 (2 years)
Board and committee activities
Member of the SEEAC
Member of the remuneration committee
Member of the chairman’s committee
Outside interests
Professor of Mechanical Engineering, head of the Department of
Engineering and Deputy Vice-Chancellor at the University of Cambridge
Chair of the Physical Sciences, Engineering and Mathematics Panel in the
Research Excellence Framework – the UK Government’s review of
research in universities
Non-executive director of the Department for Business, Innovation
& Skills (BIS)
Age
61
Nationality
British
Career
Dame Ann Dowling was appointed a Professor of Mechanical Engineering
in the Department of Engineering at the University of Cambridge in 1993
(the Department of Engineering is one of the leading centres for
engineering research worldwide). Between 1999 and 2000 she was the
64
Jerome C Hunsaker Visiting Professor at MIT, subsequently becoming a
Moore distinguished scholar at Caltech in 2001. When she returned to the
University of Cambridge, she became Head of the Division of Energy, Fluid
Mechanics and Turbomachinery in the Department of Engineering,
becoming UK lead of the Silent Aircraft Initiative in 2003 – a collaboration
between researchers at Cambridge and MIT. She became head of the
Department of Engineering at the University of Cambridge in 2009. She
was appointed director of the University Gas Turbine Partnership with
Rolls-Royce in 2001 and chairman in 2009.
Between 2003 and 2008 she chaired the Rolls-Royce Propulsion and
Power Advisory Board. She chaired the Royal Society/Royal Academy of
Engineering study on nanotechnology. She is a Fellow of the Royal Society
and the Royal Academy of Engineering and is a foreign associate of the US
National Academy of Engineering and of the French Academy of Sciences.
She has been nominated President of the Royal Academy of Engineering
from September 2014.
Relevant experience and skills
Dame Ann Dowling has a strong academic and engineering background.
Having initially been a member of the SEEAC, she joined the remuneration
committee in 2012. Her contributions on both of these committees are
valued, as is her work with the BP technology advisory council, which she
also joined during 2012 and which she now chairs.
Dr Brian Gilvary
Group chief financial officer
Tenure
Appointed to the board 1 January 2012 (2 years)
Group responsibilities
Finance, tax, planning, treasury, mergers and acquisitions, investor
relations, audit, procurement and information technology activities
Chairs the group financial risk committee
Outside interests
Visiting professor at Manchester University
Age
51
Nationality
British
Career
Dr Brian Gilvary was appointed chief financial officer on 1 January 2012.
He joined BP in 1986 after obtaining a PhD in mathematics from the
University of Manchester. Following a variety of roles in the upstream,
downstream and trading in Europe and the United States, he became the
downstream’s chief financial officer and commercial director from 2002
to 2005.
He was a director of TNK-BP over two periods, from 2003 to 2005 and
from 2010 until the sale of the business and acquisition of Rosneft equity
in 2013. From 2005 until 2009 he was chief executive of the integrated
supply and trading function, BP’s commodity trading arm. In 2010 he was
appointed deputy group chief financial officer with responsibility for the
finance function.
Relevant experience and skills
Dr Brian Gilvary has 27 years of experience within BP, gaining a strong
knowledge of finance and trading, and a deep understanding of BP’s
assets and businesses, including its interests in Russia through his time on
the board of TNK-BP.
Brian has consistently worked to further strengthen the finance function.
He has also developed the company’s engagement with shareholders and
continues to focus on financial efficiency.
Brian Gilvary’s performance has been evaluated by the group chief
executive and considered by the chairman’s committee.
BP Annual Report and Form 20-F 2013 He stepped down as group chief executive of MTN Group at the end of
March 2011. He was formerly a director of a number of listed South African
companies, including Johnnic Holdings (formerly a subsidiary of the Anglo
American group of companies), Nedbank Group, Bidvest Group and
Alexander Forbes.
Relevant experience and skills
Phuthuma Nhleko’s background in engineering and his broad experience as
a chief executive of a multi-national company enables him to contribute to
the board, particularly in the areas of emerging market economies and the
evolution of the group’s strategy. His financial and commercial experience
is particularly relevant to his work on the audit committee.
Andrew Shilston
Independent non-executive director
Tenure
Appointed 1 January 2012 (2 years)
Board and committee activities
Senior independent director
Member of the audit committee
Member of the chairman’s committee
Attends the nomination committee
Outside interests
Non-executive director of Circle Holdings plc.
Chairman of Morgan Advanced Materials plc.
Age
58
Nationality
British
Career
Andrew Shilston trained as a chartered accountant before joining BP as a
management accountant. He subsequently joined Abbott Laboratories
before moving to Enterprise Oil plc in 1984 at the time of flotation. In 1989
he became treasurer of Enterprise Oil and was appointed finance director
in 1993. After the sale of Enterprise Oil to Shell in 2002, in 2003 he
became finance director of Rolls-Royce plc until his retirement on
31 December 2011.
He has served as a non-executive director on the board of Cairn Energy plc
where he chaired the audit committee.
Relevant experience and skills
Andrew Shilston has had a long career in finance within the oil and gas
industry. His knowledge and experience as a chief financial officer, firstly in
Enterprise Oil and then Rolls-Royce, and as audit committee chairman at
Cairn Energy makes him well suited as a member of BP’s audit committee.
His experience of the oil and gas industry has been important in assisting
the board in their evaluation of projects and capital expenditure. As senior
independent director he has attended meetings of the nomination
committee.
Brendan Nelson
Independent non-executive director
Tenure
Appointed 8 November 2010 (3 years)
Board and committee activities
Chairman of the audit committee
Member of the nomination committee
Member of the chairman’s committee
Outside interests
Non-executive director and chairman of the group audit committee of
The Royal Bank of Scotland Group plc.
President of the Institute of Chartered Accountants of Scotland
Member of the Financial Reporting Review Panel
Age
64
Nationality
British
Career
Brendan Nelson is a chartered accountant. He was made a partner of
KPMG in 1984. He served as a member of the UK board of KPMG from
2000 to 2006, subsequently being appointed vice chairman until his
retirement in 2010. At KPMG International he held a number of senior
positions including global chairman, banking and global chairman, financial
services.
He served six years as a member of the Financial Services Practitioner
Panel.
Relevant experience and skills
Brendan Nelson has had a long career in finance and auditing, particularly
in the areas of financial services and trading which qualifies him to chair
the audit committee and to act as its financial expert.
This is complemented by his broader business experience and his role as
the chair of the audit committee of a major bank. During the year he has
led the audit committee in meeting the many challenges from increased
changes to regulation.
Phuthuma Nhleko
Independent non-executive director
Tenure
Appointed 1 February 2011 (3 years)
Board and committee activities
Member of the audit committee
Member of the chairman’s committee
Outside interests
Non-executive director of Anglo American plc
Non-executive director and chairman of MTN Group Ltd.
Age
53
Nationality
South African
Career
Phuthuma Nhleko began his career as a civil engineer in the US and as a
project manager for infrastructure developments in southern Africa.
Following this he became a senior executive of the Standard Corporate and
Merchant Bank in South Africa. He later held a succession of directorships
before joining MTN Group, a pan-African and Middle Eastern telephony
group represented in 21 countries, as group president and chief executive
officer in 2002. During his tenure at the MTN Group he led a number of
substantial mergers and acquisitions transactions.
65
Corporate governanceBP Annual Report and Form 20-F 2013 Executive teama
As at 6 March 2014
The executive team represents the principal executive leadership of the
BP group. Its membership includes BP’s executive directors (Bob Dudley,
Iain Conn and Dr Brian Gilvary whose biographies appear on pages 61-64)
and the senior management listed below.
1
5
2
6
3
7
4
8
2 Bob Fryar
6 Lamar McKay
Key to portraits
1 Rupert Bondy
5 Bernard Looney
Rupert Bondy
Current position
Group general counsel
Executive team tenure
Appointed 1 May 2008 (5 years)
Outside interests
No external appointments
Age
52
Nationality
British
3 Andy Hopwood
7 Dev Sanyal
Bob Fryar
4 Katrina Landis
8 Helmut Schuster
Current position
Executive vice president, safety and operational risk
Executive team tenure
Appointed 1 October 2010 (3 years)
Outside interests
No external appointments
Age
50
Nationality
American
Career
Rupert Bondy is responsible for legal and compliance matters across the
BP group.
Rupert began his career as a lawyer in private practice. In 1989 he joined
US law firm Morrison & Foerster, working in San Francisco and London,
and from 1994 he worked for UK law firm Lovells in London. In 1995 he
joined SmithKline Beecham as senior counsel for mergers and acquisitions
and other corporate matters. He subsequently held positions of increasing
responsibility and, following the merger of SmithKline Beecham and
GlaxoWellcome to form GlaxoSmithKline, he was appointed senior vice
president and general counsel of GlaxoSmithKline in 2001.
In April 2008 he joined the BP group, and he became the group general
counsel on 1 May 2008.
a The ages of the executive team are correct as at 31 December 2013.
66
Career
Bob Fryar is responsible for strengthening safety, operational risk
management, and the systematic management of operations across the
BP corporate group. He is group head of safety and operational risk, with
accountability for group-level disciplines including engineering, health,
safety, security, and environment. In this capacity, he looks after the
group-wide operating management system implementation and capability
programmes.
Bob has 28 years’ experience in the oil and gas industry having joined
Amoco Production Company in 1985. From October 2010 to February
2013 Bob was executive vice president of the production division and was
accountable for safe and compliant exploration and production operations
and stewardship of resources across all regions. In addition, he was also
responsible for local government and stakeholder management and
regional integration of all exploration and production activities.
Prior to February 2013, Bob held several management positions in Trinidad,
including chief operating officer for Atlantic LNG, and vice president of
operations.
Prior to that, Bob served in a variety of engineering and management
positions in onshore US and deepwater Gulf of Mexico including petroleum
engineer, field manager, operations manager, resource manager, and asset
manager. In addition, he worked on the Vastar integration team.
BP Annual Report and Form 20-F 2013 Andy Hopwood
Katrina Landis
Current position
Chief operating officer, strategy and regions, Upstream
Current position
Executive vice president, corporate business activities
Executive team tenure
Appointed 1 November 2010 (3 years)
Outside interests
Chair of the BP Foundation
Age
55
Nationality
British
Career
Andy Hopwood is responsible for BP’s upstream strategy, including
changes to its portfolio and investment planning. He is also responsible for
the upstream regional footprint through leadership of its regional
presidents, who are the upstream’s senior leaders in the regions where the
upstream operates.
After joining BP in 1980 as a petroleum engineer, Andy gained ten years of
operating experience in the North Sea, Wytch Farm, and Indonesia, and
developing expertise in reservoir engineering in BP’s London headquarters.
In 1989 Andy joined the corporate planning team supporting the
formulation of BP’s exploration strategy, and the subsequent rationalization
of BP’s portfolio. Following this corporate work, his international
endeavours led to positions in South America, first in Mexico and then as
commercial manager for BP’s Venezuela business, prior to a return to
London as the exploration and production planning manager.
In 1999, following the BP-Amoco merger, he was appointed business unit
leader in Azerbaijan, before returning to London in 2001 as the Upstream
chief of staff. He was then appointed business unit leader for BP’s
interests in Trinidad & Tobago until 2005, when he moved to Houston to
become strategic performance unit leader for the North American gas
business.
In 2009, he joined the Upstream executive as head of portfolio and
technology and in October 2010 was appointed executive vice president,
exploration and production.
Executive team tenure
Appointed 1 May 2013
Outside interests
Independent director of Alstom SA
Founding member of Alstom’s Ethics, Compliance and Sustainability
Committee
Member of Earth Day Network’s Global Advisory Committee
Ambassador to the U.S. Department of Energy’s U.S. Clean Energy
Education & Empowerment program
Age
54
Nationality
American
Career
Katrina Landis is responsible for BP’s integrated supply and trading
activities, Alternative Energy, shipping, technology and remediation
management.
Katrina began her career with BP in 1992 in Anchorage, Alaska and held a
variety of senior roles. She was chief executive officer of BP’s integrated
supply and trading – Oil Americas – from 2003 to 2006, group vice
president of BP’s integrated supply and trading from 2007 to 2008 and
chief operating officer of BP Alternative Energy from 2008 to 2009. She
was then appointed chief executive officer of BP Alternative Energy in
2009. On 1 May 2013, she became executive vice president, corporate
business activities.
Bernard Looney
Current position
Chief operating officer, production
Executive team tenure
Appointed 1 November 2010 (3 years)
Outside interests
Member of the Stanford University Graduate School of Business
Advisory Council
Fellow of the Energy Institute
Age
43
Nationality
Irish
Career
Bernard Looney is responsible for production operations, drilling,
engineering, procurement and supply-chain management, as well as
health, safety and environment in the upstream.
Bernard joined BP in 1991 as a drilling engineer, working in the North Sea,
Vietnam and the Gulf of Mexico. In 2001 Bernard took on responsibility for
drilling operations on Thunder Horse in the Deepwater Gulf of Mexico.
In 2005 Bernard became senior vice president within BP Alaska, before
moving in 2007 to be head of the group chief executive’s office.
In 2009 he became the managing director of BP’s North Sea business in
the UK and Norway.
Bernard became executive vice president, developments, in October 2010.
He took up his current role in February 2013.
67
Corporate governanceBP Annual Report and Form 20-F 2013 Lamar McKay
Current position
Chief executive, Upstream
Executive team tenure
Appointed 16 June 2008 (5 years)
Outside interests
Member of Mississippi State University Dean’s Advisory Council
Age
55
Nationality
American
Career
Lamar McKay is responsible for the combined Upstream business which
consists of exploration, development and production.
Lamar started his career in 1980 with Amoco and has held a broad range
of positions. In 1993, he became general manager for the Arkoma Basin,
and in 1997 moved into the role of business unit leader for the Gulf of
Mexico Shelf.
During 1998-2000, he worked on the BP-Amoco merger and served as
head of strategy and planning for the worldwide exploration and production
business in London. In 2000, he became business unit leader for the
Central North Sea in Aberdeen, Scotland. In 2001, Lamar became chief of
staff for the worldwide exploration and production business, and
subsequently served as chief of staff to BP’s deputy group chief executive.
Lamar became group vice president, Russia and Kazakhstan in 2003
where he was responsible for BP’s Upstream businesses, including BP’s
interest in the TNK-BP joint venture. He served as a member of the board
of directors of TNK-BP from February 2004 to May 2007.
In May 2007, Lamar moved to Houston to assume the role of senior group
vice president, BP p.l.c. and executive vice president, BP America where
he led BP’s efforts to resolve various issues involving the Texas City
refinery, Prudhoe Bay field and US trading function. In June 2008, he
became executive vice president, special projects focusing on Russia
where he led BP’s efforts to restructure the governance framework for
TNK-BP.
In February 2009, Lamar was appointed chairman and president of BP
America Inc, serving as BP’s chief representative in the US. In October
2010, he additionally assumed the role of chief executive officer and
president for the Gulf Coast Restoration Organization.
On 1 January 2013, he became chief executive, Upstream.
Dev Sanyal
Current position
Executive vice president, and group chief of staff
Executive team tenure
Appointed 1 January 2012 (2 years)
Outside interests
Non-executive director of Man Group plc
Member of the Accenture Global Energy Board
Member of the International Business Leaders Group of The Duke of
Edinburgh’s International Award Foundation
Trustee of the Career Academy Foundation
Age
48
Nationality
British and Indian
Career
Dev Sanyal is the accountable executive for all of BP’s corporate activities
in strategy and long-term planning, risk, economics, competitor
intelligence, government and political affairs, policy and group integration
and governance.
Dev joined BP in 1989 and has held a variety of international roles in
London, Athens, Istanbul, Vienna and Dubai. He was appointed chief
executive, BP Eastern Mediterranean Fuels in 1999. In 2002, he moved to
London as chief of staff of BP’s worldwide downstream businesses. In
November 2003, he was appointed chief executive officer of Air BP. In
June 2006, he was appointed head of the group chief executive’s office.
He was appointed group vice president and group treasurer in 2007. During
this period, he was also chairman of BP Investment Management Ltd and
accountable for the group’s aluminium interests. In January 2012, he
became executive vice president, and group chief of staff.
Helmut Schuster
Current position
Executive vice president, group human resources director
Executive team tenure
Appointed 1 March 2011 (3 years)
Outside interests
No external appointments
Age
52
Nationality
Austrian
Career
Helmut Schuster became group human resources director on 1 March
2011. In this role he holds accountabilities for the BP human resources
function.
Helmut began his career working for Henkel in a marketing capacity. Since
joining BP in 1989 Helmut has held a number of major leadership roles. He
has worked in BP in the US, UK and continental Europe and within most
parts of refining, marketing, trading and gas and power. Before taking on
his current role his portfolio of responsibilities as a vice president, human
resources included the refining and marketing segment of BP, and
corporate and functions. This role saw him leading the people agenda for
roughly 60,000 people across the globe and includes businesses such as
petrochemicals, fuels value chains, lubricants and functional experts across
the corporation.
68
BP Annual Report and Form 20-F 2013 I believe that we use our committees effectively to carry out the required
oversight and governance of risk. The Gulf of Mexico committee has
continued to work to cover the wide range of litigation in which we remain
involved as a result of the Deepwater Horizon accident. This allows the
board to focus on key areas of strategy. The SEEAC visited several
operations to evaluate our safety culture and implementation of operational
standards.
As a board we focus on the delivery of long-term value to our shareholders,
but given the nature of our business we must do so in a way that is
sensitive to the societies in which we work. This means setting values and
standards of behaviour both inside and outside the company.
Fair, balanced and understandable
During the year, the board considered the changes to the UK Corporate
Governance Code in the context of BP’s governance practices. One of
these changes has been the requirement for directors to make a statement
that they consider the annual report and accounts, taken as a whole, to be
fair, balanced and understandable.
As part of our considerations, we received an early draft of the annual
report to enable time for review and comment. The audit committee and
the SEEAC then met jointly to consider the criteria for a fair, balanced and
understandable annual report and to review the processes underpinning
the compilation and assurance of the report, in relation to financial and
non-financial management information.
Following the joint meeting of the committees, the board then considered
the annual report and accounts as a whole and discussed the tone, balance
and language of the document, being mindful of new UK reporting
requirements and consistency between the narrative sections and the
financial statements. In evaluating whether the report is fair, balanced and
understandable, the board reviewed the internal processes that form the
group’s reporting governance framework, including the role of the
corporate reporting steering group, the use of content owners, and legal
and auditor review. The board’s statement on the report is outlined on
page 116.
It has been another challenging year, but one where the board has
continued to work well and learn. I look forward to 2014.
Carl-Henric Svanberg
Chairman
Governance overview
Safety, strategy, project selection and project
execution have been at the forefront of our
discussions as a board.
Introduction from the chairman
I am pleased to describe the work of the BP board and its committees in
2013. This is the end of the fourth year in which I have had the privilege to
chair the board of BP.
In this time I have been fortunate to work with a group of directors who,
through the board and its committees, have made a significant contribution
to the rebuilding of the company. While we have made good progress, we
still have work to do.
In 2013, with some of the areas of uncertainty from 2012 behind us, we
began to determine how the board would function in the future.
Shareholders will see that the number of meetings of the board and the
committees has appropriately decreased since 2012. We are moving to
what we hope will be a more established rhythm. During the year, the
nomination committee carried out a detailed review of current board skills
and the needs of the board in terms of knowledge, expertise and diversity
over the coming years. As part of this review directors were asked how the
board should operate in future. In January, as part of the 2013 board
evaluation, we reviewed this work in the context of the results of the
evaluations over the past three years.
In looking at the past year I would like to highlight just some of the areas
upon which we have focused. In 2011 the board agreed the 10-point plan,
setting a clear strategy for the company and determined the measures by
which that strategy should be evaluated. We want to be judged on the
value we generate for our shareholders and not the volume of
hydrocarbons that we produce. To do this we have to invest our capital
wisely and be clear on how we will execute our projects so that value is
maximized. All of this needs to be done without compromising on safety.
So safety, strategy, project selection and project execution have been at
the forefront of our discussions as a board.
69
Corporate governanceBP Annual Report and Form 20-F 2013 Board and committee attendance in 2013
Board
A
B
Audit committee
A*
B
SEEAC
A*
B
Remuneration
committee
B
A
Gulf of Mexico
committee
B
A
Nomination
committee
B
A
Chairman’s
committee
B
A
Non-executive
directors
6c
12
12
7
7
7
7
7c
7
7
7
11
11
11
11
11
11
11
11
10
10
9
11
11
11
11
11
11
11
11
11
11
11
Carl-Henric Svanberg
Paul Anderson1
Frank Bowman
Antony Burgmans
Cynthia Carroll2
George David3
Ian Davis4
Ann Dowling
Brendan Nelson5
Phuthuma Nhleko6
Andrew Shilston7
Executive directors
Bob Dudley
Iain Conn
Brian Gilvary
Byron Grote
A = Total number of meetings the director was eligible to attend.
B = Total number of meetings the director did attend.
C Committee chairman.
* Includes a joint Audit Committee-SEEAC meeting to review BP’s system of internal control and risk management.
11
11
11
5
11
11
11
5
12c
12
12
12
12
11
6
6
6
7
7
13
13
13
13c
12
13
12
13
6
6
5
6
4c
4
4
4
4
4
4
4
3
4
3
4
6c
6
6
6
6
6
6
6
6
6
6
6
6
6
6
5
5
5
6
6
5
6
1 Paul Anderson was unable to attend the Gulf of Mexico committee meeting on 25 September 2013 due to a late change in the timing of the meeting.
2 Cynthia Carroll was unable to attend the chairman’s committee on 5 December 2013 due to personal commitments.
3 George David was unable to attend the Gulf of Mexico committee meeting on 8 March 2013 due to a clash with travel arrangements; he was unable to attend the chairman’s committee meeting on
24 July 2013 due to a late change in the timing of the meeting.
4 Ian Davis was unable to attend the meetings of the nomination and remuneration committees on 24 July 2013 due to a conflicting board meeting.
5 Brendan Nelson attended all scheduled board meetings in 2013, however he was unable to attend the board teleconference on 21 February 2013 that was called at short notice due to a prior
commitment with the Royal Bank of Scotland plc.
6 Phuthuma Nhleko was unable to attend the chairman’s committee meeting on 24 July 2013 and the board meeting on 25 July 2013 due to unforeseen urgent family commitments.
14%
14%
7 Andrew Shilston attended all scheduled board meetings in 2013, however he was unable to attend the two board teleconferences called at short notice on 16 January 2013 and 21 February 2013 due to
86%
prior commitments; he was unable to attend the audit committee meeting on 28 October 2013 due to major storms in the UK disrupting travel.
86%
Board diversity as at 31 December 2013
Board diversity as at 31 December 2013
1. Female directors
1. Female directors
2. Male directors
2. Male directors
Gender
Gender
2
2
1
1
Board diversity
BP recognizes the importance of diversity, including gender diversity, at all
levels of the company as well as the board. The company is committed to
increasing diversity across our operations and has in place a wide range of
activities to support the development and promotion of talented
individuals, regardless of gender and ethnic background.
The board operates a diversity policy which aims to promote diversity in
the composition of the board. Under this policy, director appointments are
evaluated against the existing balance of skills, knowledge and experience
on the board, with directors asked to be mindful of diversity, inclusiveness
and meritocracy considerations when examining nominations to the board.
Board diversity as at 31 December 2013
The implementation of this policy and the diversity mix of the board is
monitored through agreed metrics. The board also considered diversity as
part of the annual review of its performance and effectiveness.
1
1
The board is supportive of the recommendations contained in Lord Davies’
report Women on Boards for female board representation to increase to
Independence
15% by end 2013 and 25% by end 2015. Accordingly, the board set a goal
Independence
to increase the number of female board members by two (to a total of three
1. Executive directors
1. Executive directors
female directors) by the end of 2013. However, at the end of 2013 there
2. Non-executive directors
2. Non-executive directors
were two female directors on the board (equating to 14%). The nomination
committee has identified potential candidates with a diverse background
and it is anticipated that an appointment is likely to be made in 2014.
21%
21%
79%
79%
2
2
1
1
Gender
2
1. Female directors
2. Male directors
14%
86%
Independence
1. Executive directors
2. Non-executive directors
21%
79%
2
4
4
1
1
Geographic background
Geographic background
3
3
3
3
2
2
4
4
1
1
1. UK
1. UK
2. US
2. US
3. Europe excluding UK
3. Europe excluding UK
4. Rest of world
4. Rest of world
43%
43%
36%
36%
14%
14%
7%
7%
Non-executive director tenure
Non-executive director tenure
1. Less than 3 years
1. Less than 3 years
2. 3-6 years
2. 3-6 years
3. 6-9 years
3. 6-9 years
4. More than 9 years
4. More than 9 years
2
2
27%
27%
55%
55%
9%
9%
9%
9%
4
1
70
3
2
4
1
3
Geographic background
1. UK
2. US
3. Europe excluding UK
4. Rest of world
43%
36%
14%
7%
27%
55%
9%
9%
Non-executive director tenure
1. Less than 3 years
2. 3-6 years
3. 6-9 years
2
4. More than 9 years
BP Annual Report and Form 20-F 2013
Appointment and time commitment
The chairman and NEDs have letters of appointment; there is no term limit
on a director’s service as BP proposes all directors for annual re-election by
shareholders (a practice followed since 2004). While the chairman’s
appointment letter sets out the time commitment expected of him, the
letters of appointment for NEDs do not set a fixed time commitment as it
is anticipated that the time required of directors may fluctuate depending
on demands of BP business and other events. It is expected that directors
will allocate sufficient time to the company to perform their duties
effectively.
Executive directors are permitted to take up one external board
appointment, subject to the agreement of the chairman. Fees received for
an external appointment may be retained by the executive director and are
reported in the annual report on remuneration (see page 106).
Independence and conflicts of interest
NEDs are expected to be independent in character and judgement and free
from any business or other relationship which could materially interfere
with the exercise of that judgement.
Antony Burgmans joined the board in February 2004 and by the time of the
2014 AGM will have served ten years as a director. In 2012, the board
asked him to remain as a director until the 2016 AGM as it considered that
his experience as the longest serving board member provides valuable
insight, knowledge and continuity. The board has determined that he
continues to meet the board’s criteria for independence and will keep this
under review.
The board is satisfied that there is no compromise to the independence of,
and nothing to give rise to conflicts of interest for those directors who
serve together as directors on the boards of outside entities or who have
other appointments in outside entities. The nomination committee keeps
under review the other interests of the NEDs to ensure that the
effectiveness of the board is not compromised.
Succession
Dr Byron Grote, an executive director, retired from the board at the AGM in
2013. There were no other changes to the board or committee
membership during the year.
How the board works
Board governance in BP
The system of governance within which the BP board operates is set out in
the BP board governance principles. These define the role of the board, its
processes and its relationship with executive management. This system is
reflected in the governance of the group’s subsidiaries. The board
governance principles can be found at bp.com/governance.
Role of the board
The board is responsible for the overall conduct of the group’s business
and the directors have duties under both UK company law and BP’s articles
of association.
The primary tasks of the board include:
Active consideration and direction of long-term strategy, and
approval of the annual plan.
Monitoring of BP’s performance against the strategy and plan.
Obtaining assurance that the material risks to BP are identified and
that systems of risk management and control are in place to
mitigate such risk.
Board and executive management succession.
Specific tasks are delegated to the board committees (see the reports of
the committees on page 74). The board seeks to set the ‘tone from the
top’ for BP by working with management to agree the values of the
company and considering specific issues, including health, safety, the
environment and reputation.
Board composition
On 31 December 2013 the board had 14 directors – the chairman, three
executive directors and 10 independent, non-executive directors (NEDs).
The nomination committee keeps the balance and independence of the
board under review (see the report of the nomination committee on
page 79).
Key roles and responsibilities
The chairman
Carl-Henric Svanberg
• Provides leadership of the board.
• Acts as main point of contact between the board and management.
• Speaks on board matters to shareholders and other parties.
• Ensures that systems are in place to provide directors with accurate,
timely and clear information to enable the board to operate effectively.
• Is responsible for the integrity and effectiveness of the BP board’s
system of governance.
The group chief executive
Bob Dudley
• Is responsible for day-to-day management of the group.
• Chairs the executive team (ET), the membership of which is set out
on page 66.
The senior independent director
Andrew Shilston
• Is available to shareholders if they have concerns that cannot be
addressed through normal channels.
Antony Burgmans, BP’s longest serving non-executive director, acts as an
internal sounding board for the chairman and serves as intermediary for the
other directors with the chairman when necessary.
Neither the chairman nor the senior independent director is employed as
an executive of the group. The nomination committee keeps succession
plans for the chairman, senior independent director, group chief executive
and senior management under review.
71
Corporate governanceBP Annual Report and Form 20-F 2013
The IAB is chaired by BP’s previous chairman, Peter Sutherland. Its
membership in 2013 included Kofi Annan, Lord Patten of Barnes, Josh
Bolten, President Romano Prodi, Dr Ernesto Zedillo and Dr Javier Solana.
The chairman and chief executive attend meetings of the IAB. Issues
discussed during the year included events in the Middle East, the US
budget deficit and BP’s activities in Azerbaijan and North Africa.
Board effectiveness
Induction and board learning
On joining BP, non-executive directors are given a tailored induction
programme. This includes one-to-one meetings with management, the
external auditors and site visits to operations. The induction also covers
governance, duties of directors and the board committees that a director
will join.
To help develop an understanding of BP’s business, the board continues its
learning through briefings and site visits. In 2013, the board received
briefings on BP’s code of conduct, the group’s values and key business
developments including legal updates, the economic outlook and the
BP Energy Outlook. At its board meetings in Houston and India, the board
met local management.
Non-executive directors are expected to attend at least one site visit per
year. During 2013, the board made a number of visits, including to
Canadian oil sands operations, India and the Gelsenkirchen refinery in
Germany. Members of the SEEAC made site visits to BP’s operations in
Alaska and Tangguh. The chairman and Iain Conn, chief executive of BP’s
Downstream segment, visited the Whiting Refinery in the US. After each
site visit, the board or appropriate committee is briefed on the impressions
gained by the directors attending the visit.
Board visit to India
In 2013, the BP board met for the first time in India to gain an
understanding of the opportunities and challenges in the country. In
2011, BP acquired a 30% stake in 21 oil and gas production-sharing
contracts operated by Reliance Industries in India; the deal represents
one of the largest ever foreign direct investments into the country.
The board visited the Kakinada onshore terminal and discussed the
complexities of geology off the east coast of India with representatives
from Reliance. During the visit, the board also met with government
dignitaries and business partners.
In meeting the Honourable President of India, Pranab Mukherjee, BP
chairman Carl-Henric Svanberg affirmed, “We are working closely with
the government of India in its quest for energy security. I am confident
that, working together with our partners Reliance Industries, our
combined capabilities, experience and expertise in deep water will
support the efficient and cost-effective development of India’s energy
resources.”
Board activity
The board’s activities are structured to enable the directors to fulfil their
role, in particular with respect to strategy, monitoring, assurance and
succession. The diagram below shows the main areas of focus by the
board during 2013.
Board activities
Strategy
• Competitor outlook.
• Strategy principles.
• Exploration.
• Strategy away day.
• Organizational capability.
Performance
• Chief executive’s report.
• Capital investment review.
• Projects framework.
• Business review.
• BP’s activities in India.
Risk
• Group risk process.
• Global economic climate.
• Russia.
• Reputation management.
• Delivery of the
10-point plan.
Finance and
planning
• Group financial outlook.
• Quarterly and full year
results.
Reputation
• Employee feedback
survey.
• BP brand and global
reputation.
• Annual Report and
Form 20-F.
• 2014 plan.
• Shareholder distributions.
• Investor audit.
• Other investor feedback.
Board
development
• Board evaluation.
• Code of conduct and
BP values.
• AGM feedback.
• Visits to Canadian oil
sands, India and
Gelsenkirchen refinery
(Germany).
Risk and assurance
During the year the board through its committees, regularly reviewed the
processes whereby risks are identified, evaluated and managed. The
effectiveness of the group’s system of internal control and risk
management were also assessed (see Internal Control Revised Guidance
for Directors (Turnbull) on page 110).
The annual plan and the group strategy are central to BP’s risk
management programme. They provide a framework in which the board
can consider significant risks, manage the group’s overall risk exposure and
underpin the delegation and assurance model for the board in its oversight
of executive management and other activities. The board and its
committees (principally audit, SEEAC and Gulf of Mexico committees)
monitored the group risks which had been allocated following the board’s
review of the annual plan at the end of 2012.
Those group risks reviewed during 2013 included risks associated with the
global economic climate, the delivery of BP’s 10-point plan, the group’s
exposure to Russia and reputation management. The board considered at
the half year whether any changes were required to the allocation of group
risks and confirmed the schedule for oversight of these risks.
The group risks allocated for review by the board in 2014 include delivery of
BP’s 10-point plan and geopolitical risk associated with BP’s operations
around the world. The board’s monitoring committees (audit, safety, ethics
and environment assurance and Gulf of Mexico committees) were also
allocated a number of group risks for review over the year: these are
outlined in the reports of the committees on page 74. Further information
on BP’s system of risk management is outlined in Our management of risk
on page 49.
International advisory board
BP’s international advisory board (IAB) advises the chairman, group chief
executive and the board on geopolitical and strategic issues relating to the
company. This group has an advisory role and meets twice a year –
although its members are on hand to provide advice and counsel when
needed.
72
BP Annual Report and Form 20-F 2013
Board evaluation
Each year BP undertakes a review of the board, its committees and
individual directors. The chairman’s own performance is evaluated by the
chairman’s committee (led by Antony Burgmans).
In 2013 the nomination committee undertook a review of board skills, activities
and time commitment with a view to informing the succession profile of future
board appointments. This was undertaken to ensure that the board was well
positioned to challenge and develop BP’s strategy. This review included a
discussion on how the board should approach its work in future.
Given this review of board skills and the use of external facilitation in prior
years, an internally designed board evaluation has been carried out for 2013
using an external facilitator (Lintstock), which tested key areas of the
board’s work, including strategy, assurance, risk and governance
processes. The output of the review were discussed at the board and
individually at each committee in January 2014.
Key conclusions from the evaluation
The evaluation concluded that progress had been made in improving the
rhythm of board meetings and the timeliness of board paper distribution
through the introduction of an online portal.
Good progress had been made during the year on the development of
strategy and the governance around capital projects. Further work in both
these areas was agreed for 2014. In addition, greater focus on technology
and capability would be included as part of the board’s considerations on
strategy. The board also expressed a desire to look outwards when
considering the rapidly evolving global energy market.
Follow up from our previous evaluation
After the 2012 evaluation, the board revised its agenda to increase the
focus on strategic issues and introduced the regular use of forward agenda
planning to enable this to be realized. The board also asked for greater
interaction with the international advisory board, and a joint meeting has
been scheduled for 2014. The number of board meetings reduced from 19
in 2012 to 11 in 2013, enabling the board to move back to a more steady
state of operation.
Shareholder engagement
The company operates an active investor relations programme and the
board receives feedback on shareholder views through results of an
anonymous investor audit and reports from management and directors
who interacted with shareholders over the year.
Institutional investors
Executive directors and senior management regularly meet with
institutional investors through roadshows, group and one-to-one meetings
and events for socially responsible investors.
During the year the chairman, senior independent director and chairs of the
SEEAC and remuneration committee held investor meetings to discuss
strategy, the board’s view on the company’s performance, governance and
remuneration. An annual investor event was held in March 2013 with the
chairman and chairs of the board committees. This meeting enables BP’s
largest shareholders to hear about the work of the board and its
committees, and for non-executive directors to engage with investors.
Materials from investor presentations, including our financial results and
information on the work of the board and its committees can be
downloaded at bp.com/investors.
Private investors
Following a successful meeting in 2012, BP repeated an event for private
investors in conjunction with the UK Shareholders’ Association (UKSA). A
group of 50 private shareholders listened to presentations from the
chairman and head of investor relations on BP’s annual results, strategy
and the work of the board. The event gave shareholders the opportunity to
ask questions on BP’s activities and for the company to receive direct
private shareholder feedback.
As part of the further development of BP’s retail shareholder strategy, we
commenced a ‘lost shareholder’ programme in 2013 to trace and confirm
shareholders’ contact details in order to successfully reunite them with
their unclaimed dividends. Funds returned to shareholders as at 31 January
2014 amounted to £1,512,882.
AGM
The voting levels for the 2013 AGM saw an increase over the previous year
to 64.2% (versus 63.2% in 2012). A webcast, speeches and presentations
from the AGM are available on the BP website after the meeting, together
with the outcome of voting on each resolution. Each year the board
receives a report after the AGM giving a breakdown of the vote and
investor feedback on their voting decisions for the meeting, informing the
board on any issues arising.
UK Corporate Governance Code compliance
BP complied throughout 2013 with the provisions of the UK Corporate
Governance Code, except in the following aspects:
B.3.2 Letters of appointment do not set out fixed-time commitments
since the schedule of board and committee meetings is subject to
change according to the demands of business and other events. All
directors are expected to demonstrate their commitment to the
work of the board on an ongoing basis. This is reviewed by the
nomination committee in recommending candidates for annual
re-election.
D.2.2 The remuneration of the chairman is not set by the remuneration
committee. Instead the chairman’s remuneration is reviewed by the
remuneration committee which makes a recommendation to the
board as a whole for final approval, within the limits set by
shareholders. This wider process enables all board members to
discuss and approve the chairman’s remuneration (rather than solely
the members of the remuneration committee).
E.2.4 Printed copies of the BP Annual Report and Form 20-F 2012
completed mailing outside of the Governance Code period of 20
working days before the AGM (but within the UK Companies Act
notice period). This was due to printing being delayed following
developments in the company’s legal proceedings in the US.
73
Corporate governanceBP Annual Report and Form 20-F 2013 Committee reports
Audit committee
Chairman’s introduction
The work of the audit committee in 2013 has been focused on three key
themes. Firstly, financial reporting and accounting judgements, particularly
with respect to assessing BP’s financial responsibilities arising from the
Deepwater Horizon accident. Secondly, reviews of key group-level risks
and BP’s system of controls and risk management. Thirdly, regular reports
which assist the committee in maintaining assurance over the
management of financial risk and in overseeing the performance of the
external auditor. These have been supplemented by private meetings of
the committee with key constituents, including our group audit function,
the group ethics and compliance officer and lead external audit partners.
The monitoring committees of the audit, SEEA and Gulf of Mexico have
continued to operate according to agreed areas of oversight that enable
them to inform the wider board’s view. As chair of the audit committee,
I reported after each meeting to the board on the main matters discussed in
our meeting to ensure all directors were informed of the committee’s work.
I believe the mix of skills and experience amongst the committee’s
members, together with the ability to discuss issues directly with
management has led to an effective performance from the committee over
the year.
Brendan Nelson
Committee chair
Role of the committee
The committee monitors the effectiveness of the group’s financial
reporting and systems of internal control and risk management.
Key responsibilities
• Monitoring and obtaining assurance that the management or mitigation
of financial risks are appropriately addressed by the group chief
executive and that the internal control system is designed and
implemented effectively in support of the limits imposed by the board
(‘Executive Limitations’) as set out in the BP board governance
principles;
• Reviewing financial statements and other financial disclosures and
monitoring compliance with relevant legal and listing requirements;
• Reviewing the effectiveness of the group audit function and BP’s
internal financial controls and systems of internal control and risk
management;
• Overseeing the appointment, remuneration, independence and
performance of the external auditor and the integrity of the audit process
as a whole, including the engagement of the external auditor to supply
non-audit services to BP;
• Reviewing the systems in place to enable those who work for BP to
raise concerns about possible improprieties in financial reporting or other
issues and for those matters to be investigated.
74
Members
Name
Membership status
Brendan Nelson
(chairman)
Member since November 2010; chairman since
April 2011
George David
Member since February 2008
Phuthuma Nhleko Member since February 2011
Andrew Shilston Member since February 2012
Brendan Nelson is chair of the audit committee. He was formerly vice
chairman of KPMG, is chairman of the group audit committee of The Royal
Bank of Scotland Group plc, a member of the Financial Reporting Review
Panel and president of the Institute of Chartered Accountants of Scotland.
The board is satisfied that Mr Nelson is the audit committee member with
recent and relevant financial experience as outlined in the UK Corporate
Governance Code. It considers that the committee as a whole has an
appropriate and experienced blend of commercial, financial and audit
expertise to assess the issues it is required to address. The board also
determined that the audit committee meets the independence criteria
provisions of Rule 10A-3 of the US Securities Exchange Act of 1934 and
that Mr Nelson may be regarded as an audit committee financial expert as
defined in Item 16A of Form 20-F.
Meetings are also attended by the chief financial officer, group controller,
chief accounting officer, group auditor (head of group audit) and external
auditor.
Activities during the year
Training
The committee received technical updates from the chief accounting
officer on developments in financial reporting and accounting policy.
Externally facilitated learning sessions were held on the UK government
programme on cyber-security, global trends in fraud and corruption and
developments in oil and gas accounting.
Financial disclosure
The committee reviewed the quarterly, half-year and annual financial
statements with management, focusing on the integrity and clarity of
disclosure, compliance with relevant legal and financial reporting standards
and the application of critical accounting policies and judgements.
In conjunction with the SEEAC, the committee examined whether the
BP Annual Report 2013 was fair, balanced and understandable and
provided the information necessary for shareholders to assess the group’s
performance, business model and strategy. The process the two
committees and then the full board undertook as part of this examination is
outlined in the introduction from the chairman in the Governance overview
(see page 69).
Accounting judgements and estimates
Areas of significant judgement considered by the committee during the
year and how these were addressed included:
• Oil and natural gas accounting
BP uses judgement and estimations when accounting for oil and gas
exploration, appraisal and development expenditure and determining the
group’s estimated oil and gas reserves. The committee reviewed
judgemental aspects of oil and gas accounting as part of the company’s
quarterly due diligence process. It also examined the governance
framework for the oil and gas reserves process, training for staff and
developments in regulations and controls.
• Recoverability of asset carrying values
Determination as to whether and how much an asset is impaired
involves management judgement and estimates on highly uncertain
matters such as future pricing or discount rates. Judgements are also
required in assessing the recoverability of overdue receivables and
deciding whether a provision is required.
The committee reviewed the discount rates for impairment testing as
part of its annual process and examined the assumptions for long-term
oil and gas prices and refining margins. Following political and economic
developments in Egypt, the committee reviewed at each quarter with
management whether the group’s financial assets were impaired.
BP Annual Report and Form 20-F 2013 Audit committee focus in 2013
• Financial results announcements.
• Annual Report and Form 20-F.
• Accounting judgements and estimates.
• Developments in financial reporting
and accounting.
• Oil and gas reserves disclosures.
• Fair, balanced and understandable.*
• Review of effectiveness of BP’s system of
internal control and risk management.*
• Group audit reports.
• Fraud and misconduct reports.
• Ethics and compliance reports.
• Annual ethics certification.*
* Undertaken jointly with the SEEAC.
Financial
disclosure
System of internal
control and risk
management
External
audit
Risk
reviews
• External auditor independence
confirmation.
• Non-audit fees – policy and approval.
• Audit plan, fees and engagement.
• Auditor performance and effectiveness.
• Key areas of judgement for year end audit.
• Audit tendering.
• Cybersecurity.
• Trading.
• Compliance with business regulations.
• Succession and development in finance.
• Effectiveness of investment.
• Acquisitions of interests in other entities
BP exercises judgement when assessing the level of control obtained in
a transaction to acquire an interest in another entity and when
determining the fair value of assets acquired and liabilities assumed. The
committee examined the accounting for BP’s transaction with Rosneft
and the judgement on whether the group has significant influence over
Rosneft, as where such influence exists, equity accounting is applied –
resulting in the recognition of BP’s share of Rosneft’s results each
quarter and the reporting of BP’s share of production and hydrocarbon
reserves. During the year the committee received reports from
management and the external auditor which assessed the extent of
significant influence, including BP’s participation in decision making
through director election to the Rosneft board and other factors.
• Taxation
Computation of the group’s tax expense and liability, the provisioning for
potential tax liabilities and the level of deferred tax asset recognition in
relation to accumulated tax losses are underpinned by management
judgement. The committee reviewed the judgements exercised on tax
provisioning as part of its annual review of key provisions.
• Derivative financial instruments
BP uses judgement when estimating the fair value of some derivative
instruments in cases where there is an absence of liquid market pricing
information – for example, long-term gas contracts which have a lengthy
duration. This approach is taken for the group’s longer-term, structured
derivative products, natural gas embedded derivatives and the forward
contracts entered into in 2012 to purchase shares in Rosneft. The
committee received reports from the external auditor on the valuation
models developed for these contracts and reviewed disclosures relating
to these instruments in the notes to the financial statements.
• Provisions and contingencies
The group holds provisions for the future decommissioning of oil and
natural gas production facilities and pipelines at the end of their
economic lives. Most of these decommissioning events are in the long
term and the requirements that will have to be met when a removal
event occurs are uncertain. Judgement is applied by the company when
estimating issues such as settlement dates, technology and legal
requirements. The committee received briefings on the group’s
decommissioning, environmental remediation and litigation provisioning,
including key assumptions used, the governance framework applied
(covering accountabilities and controls), discount rates and the
movement in provisions over time.
• Gulf of Mexico oil spill
Judgement was applied during the year to the significant uncertainties
over the provisions and contingencies relating to the incident.
The committee regularly discussed the provisioning for and the
disclosure of contingent liabilities relating to the Gulf of Mexico oil spill
with management and the external auditors, including as part of the
review of BP’s stock exchange announcement at each quarter end.
The committee examined developments relating to the interpretation of
the business economic loss claims element of the company’s
settlement with the Plaintiffs’ Steering Committee, including US court
rulings and monitored legal developments whilst considering the
impacts on the financial statements and other disclosures.
• Pensions and other post-retirement benefits
Accounting for pensions and other post-retirement benefits involves
judgement about uncertain events, including discount rates, inflation and
life expectancy. The committee examined the assumptions used by
management as part of its annual reporting process.
Risk reviews
The group risks allocated to the audit committee for monitoring in 2013
included risks associated with trading activities, compliance with applicable
laws and regulations and security threats against BP’s digital infrastructure.
For 2014, the board has agreed that the committee will maintain monitoring
of the same group risks. The committee held in-depth reviews of these
group risks over the year, examined succession planning and capability
development in the finance function and reviewed the effectiveness and
efficiency of the capital investment of a number of BP’s major projects.
Internal control and risk management
The committee reviewed the group’s system of internal control and risk
management over the year, holding a joint meeting with the SEEAC to
discuss key audit findings and management’s actions to remedy significant
issues. The committee reviews the scope, activity and effectiveness of the
group audit function and met privately with the general auditor and his
segment and functional heads during the year.
The committee received quarterly reports on the findings of group audit,
on identified fraud and misconduct and on key ethics and compliance
issues. A further joint meeting with the SEEAC was held to discuss the
annual certification report of compliance with the BP code of conduct. The
two committees also met to discuss the group audit and ethics and
compliance programmes for 2013. The committee held a private meeting
with the group ethics and compliance officer during the year.
External audit
The external auditors started the audit cycle with their plan which identified
key audit risks to be monitored during the year – including exposures
relating to the Gulf of Mexico oil spill, estimation of oil and gas reserves,
estimation of pension liabilities, recoverability of the group’s financial
assets in Egypt and future commodity prices and their impact on the
carrying value of the group’s assets. The committee received updates
during the year on the audit process, including how the auditors had
challenged the group’s assumptions on these issues.
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Corporate governanceBP Annual Report and Form 20-F 2013
The audit committee annually reviews the fee structure, resourcing and
terms of engagement for the external auditor. Fees paid to the external
auditor for the year were $53 million, of which 9% was for non-assurance
work (see Financial statements – Note 37). Non-audit or non-audit related
assurance fees were $5 million (2012 $7 million). The $2-million reduction
in non-audit fees relates primarily to reduced corporate finance
transactions and lower tax advisory services. Non-audit or non-audit
related assurance services consisted of tax compliance services, tax
advisory services and services relating to corporate finance transactions.
The audit committee is satisfied that this level of fee is appropriate in
respect of the audit services provided and that an effective audit can be
conducted for this fee.
The effectiveness of the audit process was evaluated through a committee
review and a survey of employees in the group’s finance function. The
2013 evaluations concluded that there was a good quality audit process
and that the external auditors were regarded as knowledgeable and
capable, with an ability to challenge the BP team constructively and to
ensure balanced reporting. There was also support for the independence
of the external auditors and feedback that they should continue sharing
good industry practice.
The committee held private meetings with the external auditors during the
year and the committee chair met privately with the external auditor before
each meeting.
Auditor appointment and independence
The committee considers the reappointment of the external auditor each
year before making a recommendation to the board and shareholders. The
committee assesses the independence of the external auditor on an
ongoing basis and the external auditor is required to rotate the lead audit
partner every five years and other senior audit staff every seven years. No
partners or senior staff associated with the BP audit may transfer to the
group. The current lead partner has been in place since the start of 2013.
Audit tendering
During the year the committee considered the group’s position on its audit
services contract following changes to the UK Corporate Governance Code
and proposed European Union regulations concerning the audit market.
The committee examined a number of options regarding the timing of
tendering for BP’s external audit, including the mandatory rotation of the
group’s audit firm envisaged by proposed European regulations.
In view of the uncertainty regarding the form and impact of these
regulations, the committee concluded that the best interests of the group
and its shareholders would be served by utilizing the transition
arrangements outlined by the FRC and retaining BP’s existing audit firm
until the conclusion of the term of its current lead partner. Accordingly the
committee intends that the audit contract will be put out to tender in 2016,
in order that a decision can be taken and communicated to shareholders at
BP’s AGM in 2017; the new audit services contract would then be
effective from 2018.
Non-audit services
Audit objectivity and independence is safeguarded through the limitation of
non-audit services to tax and audit-related work which falls within defined
categories. BP’s policy on non-audit services states that the auditors may
not perform non-audit services that are prohibited by the SEC, Public
Company Accounting Oversight Board (PCAOB) and UK Auditing Practices
Board (APB). The categories of approved and prohibited services are
outlined below.
The audit committee approves the terms of all audit services as well as
permitted audit-related and non-audit services in advance. The external
Permitted and non-permitted audit services
Permitted services
Audit related
Advice on accounting, auditing and financial reporting.
Internal accounting and risk management control reviews.
Non-statutory audit.
Project assurance/advice on business and accounting process improvement.
Due diligence (acquisition, disposals, joint arrangements).
Tax compliance.
Direct and indirect tax advisory services.
Transaction tax advisory services.
Assistance with tax audits and appeals.
Tax compliance/advisory relating to human capital and performance/reward.
Transfer pricing advisory services.
Tax legislative monitoring.
Tax performance advisory.
Workshops, seminars and training on an arm’s length basis.
Assistance on non-financial regulatory requirements.
Provision of independent third-party audit on BP’s Conflict Minerals Report.
Book keeping/other services related to financial records.
Financial information systems design and implementation.
Appraisal, valuation, fairness opinions, contribution in-kind.
Actuarial services.
Internal audit outsourcing.
Management functions.
HR functions.
Broker-dealer, investment advisor, banking services.
Legal services.
Expert services unrelated to audit.
Contingent fees.
Confidential or aggressive tax position transactions.
Tax services for persons in financial reporting oversight roles.
Tax services
Other services
Prohibited services
SEC principles of auditor independence
PCAOB ethics and independence rules
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BP Annual Report and Form 20-F 2013
auditor is only considered for permitted non-audit services when its
expertise and experience of the company is important. A two-tier system
for approval of audit-related and non-audit work operates. For services
relating to accounting, auditing and financial reporting matters, internal
accounting and risk management control reviews or non-statutory audit,
the committee has agreed to pre-approve these services up to an annual,
aggregate level. For all other services which fall under the ‘permitted
services’ categories, approval above a certain financial amount must be
sought on an individual engagement basis. Any proposed service not
included in the permitted services categories must be approved in advance
either by the audit committee chairman or the audit committee before
engagement commences. The audit committee, chief financial officer and
group controller monitor overall compliance with BP’s policy on audit-
related and non-audit services, including whether the necessary pre-
approvals have been obtained.
Committee review
The audit committee undertakes an annual evaluation of its performance
and effectiveness. In 2013 the committee used an online survey which
examined governance processes such as the mix of experience and skills
amongst members, meeting content, information, training and resources.
Areas of focus for 2014 arising from the evaluation included monitoring the
length of committee papers, the inclusion of broader business topics on
the agenda and suggestions for further committee training.
Safety, ethics and environment assurance
committee (SEEAC)
Chairman’s introduction
The SEEAC has continued to monitor closely and provide constructive
challenge to management in the drive for safe and reliable operations at all
times. This has included the committee receiving specific reports on the
company’s management of high priority risks in shipping, wells, pipelines,
facilities and non-operated joint arrangements. The committee has also
undertaken a number of field visits as described in more detail below as
well as maintained its schedule of regular meetings with executive
management.
The SEEAC has continued to receive regular reports from the independent
experts that it has engaged in both the Upstream (Carl Sandlin) and in the
Downstream (Duane Wilson). They have provided valuable insights and
advice on many aspects of process safety and we are grateful to them for
their work.
Paul Anderson
Committee chair
Role of the committee
The role of the SEEAC is to look at the processes adopted by BP’s
executive management to identify and mitigate significant non-financial
risk. This includes the committee monitoring the management of personal
and process safety and receiving assurance that processes to identify and
mitigate such non-financial risk are appropriate in design and effective in
implementation.
Key responsibilities
The committee receives specific reports from the business segments but
also receives cross-business information from the functions. These include,
but are not limited to, the safety and operational risk function, group audit,
group ethics and compliance and group security. The SEEAC can access any
other independent advice and counsel if it requires, on an unrestricted basis.
The committee met seven times in 2013, including joint meetings with the
audit committee. At one of the joint meetings the committee reviewed the
general auditor’s report on the system of internal control and risk
management for the year in preparation for the board’s report to shareholders
in the annual report (see ‘Internal Control Revised Guidance for Directors’
(Turnbull) on page 110). In that joint meeting the committees also reviewed
the general auditor’s audit programme for the year ahead to ensure both
committees endorsed the coverage. The SEEAC and audit committee
worked together, through their chairs and secretaries, to ensure that the
agendas did not overlap or omit coverage of any key risks during the year.
In addition to the committee membership, all of the SEEAC meetings were
attended by the group chief executive, the executive vice president for
safety and operational risk (S&OR) and the general auditor or his delegate.
The external auditor also attended some of the meetings (and was briefed
on the other meetings by the chair and secretary to the committee). The
group general counsel and the group ethics and compliance officer also
attended certain meetings. The committee scheduled private sessions for
the committee members only (without the presence of executive
management) at the conclusion of each meeting to discuss any issues
arising and the quality of the meeting.
Members
Name
Membership status
Paul Anderson
(chairman)
Member since February 2010; chairman since
December 2012
Frank Bowman Member since November 2010
Antony
Burgmans
Member since February 2004
Cynthia Carroll
Member since June 2007
Ann Dowling
Member since February 2012
Activities during the year
Safety, operations and environment
The committee received regular reports from the S&OR function, including
quarterly reports prepared for executive management on the group’s
health, safety and environmental performance and operational integrity.
These included quarter-by-quarter measures of personal and process
safety, environmental and regulatory compliance and audit findings.
Operational risk and performance forms a large part of the committee’s
agenda.
During the year the committee received specific reports on the company’s
management of risks in shipping, wells, pipelines, facilities and non-
operated joint arrangements. The committee reviewed these risks, and risk
management and mitigation, in depth with the relevant executive
management.
Independent expert – Upstream
Mr Carl Sandlin continued in his role as an independent expert to provide
further oversight and assurance regarding the implementation of the Bly
Report recommendations. He has twice reported directly to the SEEAC in
2013, and presented detailed reports on his work, including reporting on a
number of visits he has made to company operations around the world.
He will again report to SEEAC in early 2014.
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Corporate governanceBP Annual Report and Form 20-F 2013
External and
internal audit
Risk reviews
• External auditor assurance of
sustainability reporting.
• Group audit assurance of system of
internal control.
• S&OR audit assurance (as part of group
audit).
• Explosion or release at facilities.
• Non-operated joint arrangements.
• Well incident.
• Pipeline incident.
• Marine incident.
Gulf of Mexico committee
Introduction from committee chairman
The Gulf of Mexico committee continues to oversee the group’s response
to the Deepwater Horizon accident, ensuring that the company fulfils all of
its legitimate obligations whilst protecting and defending the interests of
the group. In the past year, the focus has been on the review of ongoing
proceedings in multi-district litigation 2179 and 2185; of the assessment of
natural resource damages; and of a number of other legal proceedings in
relation to the Deepwater Horizon accident.
I believe the committee has been thorough in the execution of its duties.
The high frequency of meetings and long tenure of committee
membership has enabled members to review an evolving and complex
spectrum of issues.
Ian Davis
Committee chair
Role of the committee
The Gulf of Mexico committee was formed in July 2010 to oversee the
management and mitigation of legal and licence-to-operate risks arising out
of the Deepwater Horizon accident and oil spill. The committee’s work is
integrated with that of the board, which retains ultimate accountability for
oversight of the group’s response to the accident.
SEEAC focus in 2013
• GCE operations risk reports.
• Quarterly reports on HSE performance and operational
integrity.
• Sustainability reporting annual overview.
• Fair, balanced and understandable.*
• Field trips led by SEEAC (recent visits include
Canada oil sands, Tangguh LNG, Alaska North
Slope and Gelsenkirchen refinery).
Monitoring of
operations and
reporting
• Review of effectiveness of BP’s system of
internal control and risk management.*
• Quarterly group audit reports.
• Quarterly significant allegations and investigations reports.
• Quarterly ethics and compliance reports.
• Annual ethics certification.*
System of internal
control and risk
management
* Undertaken jointly with the audit committee.
Process safety expert – Downstream
Mr Duane Wilson continued to report to the committee in his role as
process safety expert for the Downstream segment. In this role he
continues to work with segment management on a worldwide basis
(having previously focused on US refineries) to monitor and advise on the
process safety culture and learnings across the segment. He twice
reported directly to the SEEAC in 2013 and presented detailed reports on
his work (including reporting on a number of visits he has made to
refineries and other downstream facilities).
Reports from group audit and group ethics & compliance
The committee received quarterly reports from both of these functions.
These included summaries of investigations into significant alleged fraud or
misconduct. In addition, both the general auditor and the group ethics and
compliance officer met in private with the chairman and other members of
the committee.
Field trips
In April the chairman and all other members of the committee visited
Alberta, Canada to examine the oil sands being developed there by the
group and third parties. In October a committee member visited operations
at the Tangguh LNG facility in West Papua in Indonesia while another
committee member travelled to Alaska and visited operations on the North
Slope. In addition, three members of the committee visited the
Gelsenkirchen refinery in Germany. In all cases, the visiting committee
members received briefings on operations and the status of local operating
management system (OMS) implementation and risk management and
mitigation. For each visit, committee members then reported back in detail
to the committee and subsequently to the full board.
Committee review
For its 2013 evaluation, the SEEAC used a questionnaire administered by
external consultants to examine the committee’s performance and
effectiveness. The committee responded to the same questions used in
2012 so that any change trends could be discerned. The topics covered
included the balance of skills and experience among its membership, the
quality and timeliness of the information the committee receives, the level
of challenge between committee members and management and how
well the committee communicates its activities and findings to the board.
The evaluation results were generally positive. Committee members
considered that the committee possessed the right mix of skills and
background, had an appropriate level of support and had received open and
transparent briefings from management. The committee considered that
the field trips made by its members had become an important element in
the work of the committee, in particular through such trips giving
committee members the ability to examine how risk management is being
embedded in businesses and facilities.
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BP Annual Report and Form 20-F 2013
GoM committee focus in 2013
Integrated legal strategy including:
• Multi-district litigation 2179 and 2185.
• Natural resource damages.
• Suspension and debarment actions.
• Claims administration.
• Other litigation and investigations.
• Response and remediation activities.
• Natural resource damages assessment.
• Restoration projects.
Legal
Operational
Reputation
Compliance
• External affairs and community outreach.
• US government and media communications.
• Internal communications.
• Licence to operate.
• Department of Justice plea agreement.
• SEC consent order.
Key responsibilities
• Oversee the legal strategy for litigation, investigations and suspension/
debarment actions arising from the accident and its aftermath, including
the strategy connected with settlements and claims.
• Review the environmental work to remediate or mitigate the effects of
the oil spill in the waters of the Gulf of Mexico and on the affected
shorelines.
• Oversee management strategy and actions to restore the group’s
reputation in the United States.
• Review compliance with government settlement agreements arising out
of the Deepwater Horizon accident and oil spill, including the SEC
Consent Order and the Department of Justice Plea Agreement, in
coordination with other committee and board oversight.
Members
Name
Membership status
Ian Davis (chair) Member since July 2010; committee chair since July
2010
Paul Anderson
Member since July 2010
Frank Bowman Member since February 2012
George David
Member since July 2010
Activities during the year
The committee reviewed plans and progress in moving Gulf Coast
shoreline response activities through to completion and sign-off by the US
Coast Guard. Activities are now complete in all states with the exception of
Louisiana.
The committee continued to oversee numerous legal matters relating to
the Deepwater Horizon accident, including the company’s appeals to the
US Court of Appeals for the Fifth Circuit relating to the Court-Supervised
Settlement Program and the first two phases of trial in MDL-2179.
The committee met thirteen times in 2013.
Committee review
Each year the Gulf of Mexico committee evaluates its performance and
effectiveness. In 2013, the committee again used a questionnaire
administered by external consultants covering the same questions used in
2012 in order to identify trends. Key areas covered included the balance of
skills and experience among its membership, quality and timeliness of
information and support received by the committee, the appropriateness of
committee tasks and how well the committee communicates its activities
and findings to the board. The results of the evaluation were positive.
Specific areas identified for focus in 2014 included maintaining constructive
and challenging engagement with management and of continuing timely
and effective communication of its activities and findings to the board.
Nomination and chairman’s committees
Chairman’s introduction
I am pleased to report on the two board committees which I chair. Both
have been active during the year in seeking to develop the membership of
the board and its governance.
Nomination committee
Role of the committee
The committee ensures an orderly succession of candidates for directors
and company secretary.
Key tasks
• Identify, evaluate and recommend candidates for appointment or
reappointment as directors.
• Identify, evaluate and recommend candidates for appointment as
company secretary.
• Keep under review the mix of knowledge, skills and experience of the
board to ensure the orderly succession of directors.
• Review the outside directorship/commitments of the non-executive
directors.
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Corporate governanceBP Annual Report and Form 20-F 2013
Finally, the committee reviewed the current composition of the board and
independence of non-executive directors, and recommended to
shareholders all directors for re-election at the 2013 AGM.
Committee review
The committee undertook an annual evaluation of its effectiveness and
performance, using a questionnaire. The review concluded that there had
been an improvement in the timeliness of distribution of pre-read and that
the longer session focusing on board composition, skills and the fit with
the group’s strategy had been valuable and should be repeated annually.
Chairman’s committee
Role
To provide a forum for matters to be discussed amongst the non-executive
directors.
Tasks
• Evaluate the performance and the effectiveness of the group chief
executive (GCE).
• Review the structure and effectiveness of the business organization
of BP.
• Review the systems for senior executive development and determine
the succession plan for the GCE, the executive directors and other
senior members of executive management.
• Determine any other matter which is appropriate to be considered by all
of the non-executive directors.
• Opine on any matter referred to it by the chairman of any committees
comprised solely of non-executive directors.
Members
The committee comprises all the non-executive directors who join the
committee at the date of their appointment to the board. The chief
executive attends the committee when requested.
Activities
The committee met six times during the year.
The committee reviewed:
• The performance of the chairman and the chief executive early in the
year. Parameters were set for evaluations in 2014.
• The developing position in the US Courts in respect of the
implementation of the settlement with the Plaintiffs Steering
Committee, including the business economic loss claims and the
activities of the Claims Administrator, the federal judge and the appeals
court. The work of Judge Freeh was also considered.
• A number of issues relating to the company’s strategy in the light of the
views of shareholders and the market more generally.
• The chief executive’s succession plans for the executive team and senior
leaders. The committee also considered the organization and operation
of the executive team.
Members
Name
Membership status
Carl-Henric Svanberg (chair) Member since September 2009;
committee chair since January 2010
Paul Anderson
Member since April 2012
Antony Burgmans
Member since May 2011
Cynthia Carroll
Member since May 2011
Ian Davis
Member since August 2010
Brendan Nelson
Member since April 2012
Andrew Shilston, as the senior independent director, attends all meetings
of the committee.
Activities during the year
The committee met four times during the year. At the start of the year, the
committee reflected on the output of the annual evaluation and determined
a rhythm for their meetings during the year. This would include one longer
meeting which would review board composition and skills in the light of
the company’s strategy.
The committee considered the time commitment required from non-
executive directors and in particular chairs of committees in discharging
their responsibilities. The committee determined that the time
commitment of directors had increased and this should be made clear to
those who may join the board.
The membership of the board had been substantially refreshed over the
previous three years which has resulted in no director now being
scheduled to retire earlier than the 2016 AGM. Therefore the committee
during the year reviewed the current skills of the board and those required
by the board over the coming years as the company’s strategy is
implemented.
In conducting this review the committee initiated interviews with all
directors. The conclusion of the review was that whilst the current board’s
skills matched those presently required, in seeking future candidates there
should be a greater focus on the business of BP, US government relations
and, possibly, Russia. All of this was against the background of the board’s
clear aspirations on diversity and the work of the international advisory
board in supporting the chairman and the chief executive on geo-political
issues.
As part of the review, directors were asked to comment on how the board
should work in future given that the company had substantially emerged
from the crisis in the Gulf of Mexico. The main conclusions were:
• The board was moving towards a more normal rhythm. Its operation had
improved over the past three years. The goal should be simplification
and clarity in materials and discussion. Substantial progress had been
made.
• The board should continue its focus on strategy and performance, with
the committees taking the lead on monitoring. Tasks of the board and
committees and their agendas should be reviewed to ensure that the
board was addressing the relevant strategic challenges and the
committees were complete in their monitoring task.
• There should be further focus on major projects and capital investment
to ensure that value was being created.
Against this background, the committee continued to work with an
executive search firm to identify potential candidates and to engage with
them as appropriate. The committee was aware of the board’s aspirations
on gender diversity. It is important, in the committee’s view, that any
candidates have the requisite skills to join the board. Potential candidates
with a diverse background have been identified, and it is anticipated that an
appointment will now likely be made in 2014.
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BP Annual Report and Form 20-F 2013 Directors’
remuneration
report
82
Chairman’s annual statement
84
2013 annual report on remuneration
84
95
Executive directors
Non-executive directors
96
Directors’ remuneration policy
96
107
Executive directors
Non-executive directors
C
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BP Annual Report and Form 20-F 2013
81
Chairman’s annual statement
Our remuneration system has worked
appropriately during difficult times, and I am
confident it will continue to do so as
performance returns to healthy sustained levels.
Dear shareholder
BP continued the disciplined and systematic execution of its strategy
during 2013, focusing on safety and operational risk management, and on
restoring value. As in 2012, there were many positive steps in the recovery
journey during 2013 including improved safety, a strengthened portfolio
and a new future in Russia. I encourage you to read about these in more
detail elsewhere in this annual report.
Remuneration for executive directors continues to be tied closely to this
overall recovery of the group. The vast majority of potential remuneration is
based on outcomes relative to measures related directly to the company’s
strategy and key performance indicators. In addition to a direct link to
strategy, our remuneration system has a strong bias towards sustained
long-term performance, and our decisions regarding remuneration are
guided by key principles of informed judgement, fair treatment and
alignment with shareholders. My meetings with shareholders this year
have again been helpful in understanding perspectives and have led to a
few modifications to our policy.
Our report this year reflects the new UK regulations on directors’
remuneration and so is divided into an annual report on remuneration and a
separate policy report. The annual report on remuneration sets out and
explains the outcomes of the various elements that make up 2013 total
remuneration. The policy report explains our proposed remuneration policy
for the next three years which, subject to approval by shareholders, will
come into effect from the AGM. For both sections the information relating
to executive directors (whose remuneration is determined by the
remuneration committee) is presented separately from that relating to
non-executive directors (whose remuneration is determined by the full
board).
2013 outcomes
I am pleased to report that remuneration for 2013, as summarized on
page 85, increased after several years where pay was significantly
depressed by the aftermath of the Deepwater Horizon incident. It is
particularly encouraging that a moderate portion of shares in the long-term
performance share plan has vested this year. These outcomes reflect
strong and sustained performance with safety steadily improving,
operations performing well and a portfolio of assets growing through
capital discipline and strong project management. The significant
divestments of the last few years have made the company smaller but
stronger, with improved potential to grow value.
82
Annual bonus
It was a good year for BP with improved safety, new discoveries and
operations, a strengthened portfolio and benefits already accruing from the
company’s new relationship in Russia. Overall group performance
exceeded annual plan levels and resulted in a score of 1.32 times target.
Performance was assessed relative to metrics set at the start of the year
and reflecting the company’s strategy and key performance indicators.
Safety and operational risk management accounted for 30% of annual
bonus. Led strongly from the top, this continued to show encouraging
progress with particularly significant reductions in tier 1 process safety
events and loss of primary containment – both important measures of
process safety. Results this year confirm that it remains a constant priority
throughout the business.
The company also made good gains in restoring value, which accounted
for 70% of annual bonus. Underlying replacement cost profit and total cash
costs were both better than plan targets, while operating cash flow
achieved target levels. Key operating performance was also positive with
important major projects commissioned and a significant improvement in
unplanned Upstream deferrals. Downstream operations demonstrated
high availability and good safety results but profitability was impacted by a
difficult business environment affecting refinery margins.
Deferred bonus
The first of the deferred bonus share awards, implemented in 2010,
became eligible for vesting at the end of 2013. Vesting was dependent on
safety and environmental sustainability performance over the period from
2011 through 2013. Our review confirmed very positive results during this
period with consistent improvements in key metrics and no major
incidents. Based on this positive result, the deferred and matched shares
for this period vested fully.
Performance shares
The 2011-2013 performance share plan, the first plan commencing after
the Deepwater Horizon incident, focused on value creation, reinforcing
safety and risk management and rebuilding trust. 50% of the award was
dependent on total shareholder return which failed to make the threshold
required for vesting. Reserves replacement, accounting for 20% of the
award, is expected to be very positive and progress relative to the strategic
imperatives, accounting for the remaining 30%, was very encouraging.
Overall, we expect nearly 40% of shares will vest, the highest in over
10 years.
Other elements
Salaries were increased by just under 3% for Bob Dudley, Iain Conn and
Dr Brian Gilvary mid-year. Pension increases reflect normal plan rules and
valuation according to UK regulations. The increased value reported for
Bob Dudley reflects his promotion to group chief executive in 2010 which,
because his defined benefit pension is based on three-year average
remuneration, takes a number of years to reach a steady state. In addition,
the reported value is calculated according to UK regulations and the
committee has been informed by the company’s consulting actuaries that
these significantly overstate the value of his US pension increase.
Remuneration policy
Attracting and retaining top talent is a key objective of our approach to
remuneration. Our proposed policy, as summarized on page 98, remains
largely unchanged from that which has applied for a number of years and
its continuity has been a stabilizing force during a period of company
turbulence. The core elements of salary, annual bonus, deferred bonus,
performance shares and pension continue to provide an effective, relatively
simple, performance-based system that fits well with the long-term nature
of BP’s business and strategy.
Three modifications have been included in our proposed policy as a result
of our dialogue with investors. First, we have added a three-year retention
period in the deferred bonus element for those matched shares that vest in
the plan. Second, we have made the vesting of performance shares more
stringent for those metrics based on performance relative to other oil
majors. Finally, we have added a specific review of performance share
vesting to ensure that high levels of vesting are consistent with
shareholder benefits.
All of the above are explained in more detail in the policy report.
BP Annual Report and Form 20-F 2013 EDIP renewal
The executive directors’ incentive plan (EDIP) has provided the umbrella
framework for share-based remuneration for BP executive directors since
it was first approved by shareholders in April 2000. It was renewed both in
2005 and 2010 and will expire in April 2015 according to its current
mandate. The UK Listing Rules require a separate approval for this plan
despite it largely being a duplication of what is included in the new policy
report governed by a different regulatory regime. Given that the EDIP is an
important vehicle to implement the remuneration policy, we concluded that
it was appropriate to bring its renewal forward to coincide with the first
policy vote. Details appear under resolution 19 in the Notice of Meeting,
and are consistent with those included in the policy report.
It is reassuring to see momentum building in the business, led by a
talented top team with resolve and commitment. Our remuneration
system has worked appropriately during difficult times, and I am confident
it will continue to do so as and when performance returns to healthy
sustained levels.
Antony Burgmans
Chairman of the remuneration committee
6 March 2014
Remuneration – the big picture
D e ferred bonus
2013 deferred
bonus outcomes
(2010 deferral)
see page 87
Policy
see page 101
2013 bonus
outcomes
see page 86
Safety and
environmental
sustainability
performance
2011-2013
plan outcomes
see page 88
P
e
r
f
o
r
m
a
n
c
e
Performance
relative to
annual plan
Key p e r f o
r m ance indic
a
t
o
r
s
Performance
measures
reflect strategy
and KPIs
Policy
see page 100
Strategy
s
h
a
r
e
s
Policy
see page 102
us
n
o
al b
u
n
n
A
see pages 1 8 -
Salaries
reviewed
annually taking
account of both
internal and
external
comparators
9
1
Home country
norms apply
Policy
see page 100
Policy
see page 103
2013 salary
outcomes
see page 86
S
a
l
a
r
y a
n
d benefits
2013 pension
outcomes
see page 89
n sio n
e
P
C
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p
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a
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g
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83
BP Annual Report and Form 20-F 2013
2013 annual report on remuneration
This section reports on the remuneration outcomes
for 2013 and is divided into separate sections for
executive and non-executive directors.
The remuneration of the executive directors is set by
the remuneration committee (the committee) under
delegated powers from the board. The committee
makes a recommendation to the board for the
remuneration of the chairman. The remuneration of
the non-executive directors is set by the board
based on a recommendation from the chairman, the
group chief executive and the company secretary.
84
84
86
90
91
92
93
95
(a) Executive directors
Total remuneration summary
Total remuneration in more depth (including 2014
implementation of policy)
Salary and benefits
86
Annual bonus
86
Deferred bonus
87
Performance shares
88
89
Pension
Remuneration committee
Directors shareholdings
Remuneration statistics and comparisons
Further details
(b) Non-executive directors
(a) Executive directors
Total remuneration summary
Strategy > Key performance indicators > Performance > Pay
The clear link from strategy through to pay continues. For several years the
company’s strategy has centred on enhancing safety and risk
management, rebuilding trust and restoring value. This strategy has
provided focus for key performance indicators (KPIs) and in turn the
measures for annual bonus, deferred bonus and performance share plans.
2013 summary of outcomes
These are shown in the table opposite and represent the following:
• Salary – reviewed mid-year and increased just under 3% for all except
Dr Byron Grote who retired mid-year.
• Annual bonus – overall group bonus was based 30% on safety and
operational risk (S&OR) management and 70% on restoring value.
S&OR results were good both in terms of improvement and overall
standard. Similarly, performance relative to value measures was overall
better than the annual plan. Overall group outcome was 1.32 times
target level.
The resulting cash bonuses are shown in the table opposite with total
deferred bonuses reflected in the ‘Conditional equity’ table as required
by UK regulations. Dr Byron Grote, given his retirement, was not eligible
for any deferral, and his bonus (prorated to reflect his service) was paid
in cash.
• Deferred bonus – the 2010 deferred bonus was contingent on safety
and environmental sustainability performance over the period 2011
through 2013. Overall assessment was very positive based on
continually improving safety and risk management performance and
strong evidence of ingrained safety culture and systems throughout the
organization. Based on this, 2010 deferred and matched shares
vested.
• Performance shares – the 2011-2013 plan was based 50% on total
shareholder return (TSR) and 20% on reserves replacement, both
relative to the other oil majors, and reflecting the key strategic focus on
restoring value. The final 30% was based on strategic imperatives made
up equally of safety and risk management, external reputation and staff
alignment and morale – all key strategic priorities in the period after the
Deepwater Horizon incident in 2010. 39.5% of shares in the plan are
expected to vest based on strong reserves replacement performance
and good progress against all three strategic imperatives. TSR
performance did not achieve the minimum level required for any vesting.
• Pension – pension figures reflect the UK requirements to show 20
times the increase in pension value for defined benefit schemes, as well
as any cash paid in lieu. In the case of Bob Dudley’s reported figures,
this UK requirement overstates the increase in the actuarial value of his
US pension by several million dollars.
84
BP Annual Report and Form 20-F 2013
Single figure table of remuneration of executive directors in 2013 (audited)
Annual remuneration 2013
Salary
Annual cash bonusa
Benefits
Total
Vested equity
Deferred bonus and matchb
Performance shares
Total
Remuneration is reported in the currency received by the individual
Bob Dudley
thousand
2013
$1,776
$2,344
$90
$4,210
2012
$1,726
$837
$86
$2,649
Iain Conn
thousand
Dr Brian Gilvary
thousand
Dr Byron Grote
thousand
2013
£763
£961
£59
£1,783
2012
£741
£374
£39
£1,154
2013
£700
£924
£45
£1,669
2012
£690
£366
£13
£1,069
2013
$743
$1,470
$10
$2,223
2012
$1,464
$710
$15
$2,189
$0
$4,522c
$4,522
$0
$0
$0
£242
£1,332c
£1,574
£0
£666
£666
£0
£505c
£505
£0
£299
£299
$893
$2,225c
$3,118
$0
$0
$0
£1,820
$8,732
£3,357
$2,649
Total remuneration
Pension
$6,535e
Pension value increased
Cash in lieu of future accrualf
N/A
$9,184
Total including pension
a This reflects the amount of total overall bonus paid in cash with the deferred portion set out in the conditional equity table below. The relevant portions are two-thirds cash and one-third deferred.
b This relates to the deferred bonus from prior years that vests.
c Represents the assumed vesting of shares in 2014 following the end of the relevant performance period, based on anticipated performance achieved under the rules of the plan and includes re-invested
dividends on shares vested. In accordance with UK regulations, the vesting price of the assumed vesting is the average market price for the fourth quarter of 2013 which was £4.69 for ordinary shares
and $45.52 for ADSs.
d Represents the annual increase in accrued pension multiplied by 20 as prescribed by UK regulations. For Bob Dudley the increase in actuarial value of $1,319,000 is considered to be a more accurate
reflection of the increase.
e The figure for 2012 has been restated on the same basis as 2013 to be consistent with the finalized UK regulations.
f As for all employees affected by UK pension tax limits and who wished to remain within these limits, with effect from April 2011, Iain Conn and Dr Brian Gilvary received a cash supplement of 35% of
basic salary in lieu of future service pension accrual.
£0
£259
£2,079
£46
£267
£3,670
$4,447
N/A
$13,179
£44
£245
£2,463
£1,024
£242
£2,634
$141
N/A
$5,482
$747
N/A
$2,936
$5,341
£2,174
£1,368
$2,189
Conditional equity – to vest in future years, subject to performance
Deferred bonus in respect of bonus year
Total deferred bonus
Total deferred converted to shares Shares
Total matched shares
Shares
Vesting date
Value (thousand)
2013
$1,172
149,628
149,628
Feb 2017
2012
$1,674
229,380
229,380
Feb 2016
2013
£481
100,563
100,563
Feb 2017
2012
£748
161,296
161,296
Feb 2016
2013
£462
96,653
96,653
Feb 2017
2012
£732
157,630
157,630
Feb 2016
2013
$0
0
0
Feb 2017
2012
$1,420
194,556
32,424
Feb 2016
Bob Dudley
Iain Conn
Dr Brian Gilvary
Dr Byron Grote
Performance share element
Potential maximum shares
Vesting date
2013-2015
2012-2014
1,384,026 1,343,712
Feb 2015
Feb 2016
2013-2015
694,688
Feb 2016
2012-2014
660,633
Feb 2015
2013-2015
637,413
Feb 2016
2012-2014
624,434
Feb 2015
2013-2015
142,278
Feb 2016
2012-2014
414,468
Feb 2015
85
Corporate governanceBP Annual Report and Form 20-F 2013 Total remuneration in more depth
Salary and benefits
2013 outcomes
Salaries were reviewed in May 2013 using a number of internal and
external comparisons. Externally, the competitiveness of salaries and of
overall packages relative to other oil majors, other large UK and Europe-
based international companies and related US companies were
considered. Internally the committee reviewed three distinct groups – the
overall level of increases for all employees in both the UK and the US, the
distribution and average level of increases for ‘group leaders’ comprising
around 500 top executives in the company, and finally the individual and
average increases for the top executive team.
Based on this review, salaries were increased by 2.8% for Bob Dudley
(to $1,800,000), 2.9% for Iain Conn (to £774,000) and 2.9% for
Dr Brian Gilvary (to £710,000) effective 1 July 2013.
Total benefits received by executive directors included car-related benefits,
security assistance, insurance and medical benefits. The total value of
taxable benefits is included in the summary table on page 85.
2014 implementation
The remuneration committee intends to review salaries in May 2014 and
will again consider both internal and external comparisons. Benefits will
continue unchanged.
Annual bonus
Framework
All executive directors were eligible for an overall annual bonus, including
deferral, of 150% of salary at target and 225% of salary at maximum –
unchanged since 2010.
Bob Dudley’s annual bonus was based entirely on group results, as was
Dr Brian Gilvary’s and Dr Byron Grote’s. Iain Conn’s was based 70% on
group results and 30% on his Downstream segment results.
Measures and targets for the annual bonus were set at the start of the year
and were derived from the company’s annual plan which, in turn, reflected
the company’s strategy and KPIs. Measures were grouped under the
dominant themes of S&OR management, and restoring value. Targets
were set so that meeting the plan equates to on-target bonus.
At group level, S&OR was set to account for 30% of total bonus and
included targets for loss of primary containment, process safety tier 1
events and recordable injury frequency. Value measures were set to
account for 70% of total bonus and included targets for operating cash
flow, underlying replacement cost profit, total cash costs, Upstream
unplanned deferrals, major project delivery and Downstream net income
per barrel.
Additional measures and targets were set for Iain Conn’s Downstream
segment. These focused on safety, operating efficiency and profitability.
As well as the specific measures set out, the committee considers any
other results or factors it deems relevant and applies its overall judgement
in determining final bonus outcomes.
2013 annual bonus outcomes
Measures
Safety and operational risk management
Loss of primary containment
Process safety tier 1 events
Recordable injury frequency
Value
Operating cash flow
Underlying replacement cost profit
Total cash costs
Upstream unplanned deferrals
Major project delivery
Downstream net income per barrel
Overall outcome
Weight
30.0%
10.0%
10.0%
10.0%
70.0%
16.3%
16.3%
16.3%
7.0%
7.0%
7.0%
Threshold
Target
Max
Threshold
Target
Max
Result
x target
0.60
2.00
1.55
1.05
1.65
1.50
2.00
0.50
0.68
1.32
2013 outcomes
Overall group performance outcomes for the year are summarized in the
table above.
S&OR management performance, weighted at 30%, was positive.
Process safety events declined significantly to amongst the lowest of the
oil majors. Loss of primary containment did not meet its target but still
showed an improvement of more than 10% over 2012. Recordable injury
frequency continued to show marked improvement.
Performance related to value measures were similarly positive. Underlying
replacement cost profit and total cash costs both came in better than plan
targets while operating cash flow met its plan level. Major projects met plan
with one exception and Upstream unplanned deferrals exceeded target
with a 30% improvement compared to 2012. Finally, Downstream net
income per barrel was below target reflecting difficult trading conditions.
Based on these results, the group performance factor is calculated at 1.32
times target. The committee, as is its normal practice, considered this result
in the context of the underlying performance of the group, competitors’
results, shareholder feedback and input from the board and other
committees. After review, it concluded that this represented fairly the
overall performance of the business during the year and confirmed the
score for group purposes.
In the Downstream segment, safety results were good with improvement
in most areas of process and personal safety. Performance related to value
measures was negatively impacted by compression of fuel margins and so
operating cash flow was below plan level, but other operating measures
were at or better than plan. A performance score of 1.13 times target was
achieved.
Overall bonus is determined by multiplying the group score of 1.32 times
target by the on-target bonus level of 150% of salary. Bob Dudley’s total
overall bonus therefore was 198% of salary (1.32x150%). The same score
was applied to each of the other executive directors for group outcomes
resulting in both Dr Brian Gilvary and Dr Byron Grote also receiving an
overall bonus of 198% of salary. Combined with the results for his
segment (accounting for 30% of his bonus), Iain Conn’s total overall score
was 1.26 times target, resulting in a bonus of 189% of salary.
Of the total bonuses referred to above, one-third is paid in cash, one-third
is deferred on a mandatory basis, and one-third is paid either in cash or
voluntarily deferred at the individual’s election. Dr Byron Grote, who retired
mid-year, was not eligible for deferral and so his entire bonus (reflecting his
six months of service) was paid in cash.
86
BP Annual Report and Form 20-F 2013
2013 overall bonus outcome
Bob Dudley
Iain Conn
Dr Brian Gilvary
Dr Byron Grote
Paid
in cash
Total
deferred
$2,343,660 $1,171,830
£961,380
£480,690
£924,000
£462,000
$1,470,150
$0
2014 implementation
For 2014, 100% of Bob Dudley’s and Dr Brian Gilvary’s bonus will be based
on group results. Iain Conn will again have 70% of his bonus determined on
group results and 30% on his Downstream segment results.
The committee determines specific measures and targets each year that
reflect the priorities in the group’s annual plan and KPIs, both of which are
derived from the company’s strategy. For 2014 there will be no change
from the measures and weightings used in 2013 other than a minor change
to the treatment of cost management. The table below shows the group
measures that will be used, the weight attached to each and the alignment
with KPIs and group strategy.
Targets have been agreed for each of the measures based on the annual
plan. In addition the committee uses its judgement to set the range of
bonus payouts from minimum acceptable at threshold to very stretching
but achievable at maximum.
2014 annual bonus measures
Measures
KPI
Safety and operational risk management
Loss of primary containment
Process safety tier 1 events
Recordable injury frequency
Value
Operating cash flow
Underlying replacement cost profit
Cost management
Upstream unplanned deferrals
Major project delivery
Downstream net income per barrel
Weight
30.0%
10.0%
10.0%
10.0%
70.0%
16.3%
16.3%
16.3%
7.0%
7.0%
7.0%
Link to strategy
Safe, reliable and compliant operations
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Disciplined financial choices
Competitive project execution
Focus on high-value Upstream assets
Grow our exploration position
Build high-quality Downstream businesses
Deferred bonus
Framework
One-third of the total bonus awarded to the executive directors is required
to be paid in shares under the terms of the deferred bonus element.
Deferred shares are matched on a one-for-one basis and, after three years,
vesting for both deferred and matched shares is contingent on an
assessment of safety and environmental sustainability over the three-year
deferral period.
Individuals may elect to defer up to an additional one-third of total bonus
into shares on the same basis and subject to the same contingency as the
mandatory deferral.
2013 outcomes
No bonuses were paid for group results in 2010, however both Iain Conn
and Dr Byron Grote received a limited bonus related to their segment
results that year. Deferrals from these were converted to shares, matched
one-for-one, and deferred for three years from the start of 2011. The
three-year performance period concluded at the end of 2013 and vesting
was subject to a review of safety and environmental sustainability
performance over the three-year deferral period. The committee reviewed
safety and environmental sustainability performance over this period and,
as part of this review, sought the input of the safety, ethics and
environment assurance committee (SEEAC). Over the three-year period
2011-2013 safety measures showed a steady improvement, there were no
major incidents, and the group-wide operating management system
showed good signs of driving improvement in environmental as well as
safety areas.
Based on their review, the committee approved full vesting of the deferred
and matched shares for the 2010 deferred bonus as shown in the following
table (as well as in the total remuneration summary chart on page 85).
2010 deferred bonus vesting
Name
Iain Conn
Dr Byron Grote
Shares
deferred
42,768
97,548
Vesting
agreed
100%
100%
Total shares
including
dividends
49,340
Total
value
at vesting
£241,766
110,640
$892,680
Dr Byron Grote’s vesting reflected a prorating of the matched shares
component to reflect his service. Dr Brian Gilvary participated in a separate
deferred bonus plan prior to his appointment as an executive director and
details of this are provided in the table on page 93.
Information on the deferred bonus awards made in early 2013, and
pertaining to 2012 bonuses, was set out in last year’s report and a
summary is included in the table on page 85.
2014 implementation
The remuneration committee has determined that the safety and
environmental sustainability performance hurdle will continue to apply to
shares deferred from the 2013 bonus and that there will be no change to
these measures. It has also proposed that in future all matched shares that
vest will, after sufficient shares have been sold to pay tax, be subject to an
additional three-year retention period before being released to the
individual, further reinforcing our long-term orientation. These features are
described in more detail in the policy section of the report and have been
implemented for shares deferred from the 2013 bonus.
87
BP Annual Report and Form 20-F 2013
Performance shares
Framework
Performance shares were awarded to each executive director in early 2011
with vesting after three years dependent on performance relative to
measures reflecting the company’s strategic priorities in the period after
the Deepwater Horizon accident. For the 2011-2013 plan, vesting was
based 50% on TSR compared to the peer group, 20% on reserves
replacement ratio, also relative to the peer group, and 30% on a set of
strategic imperatives for rebuilding trust. These centred on S&OR
management, rebuilding BP’s external reputation, and reinforcing staff
alignment and morale.
The peer group includes ExxonMobil, Shell, Chevron and Total.
ConocoPhillips was originally included as part of the peer group but was
removed following its demerger (with no impact on outcome in any case).
Vesting was set at 100%, 70% and 35% for performance equivalent to
first, second and third rank respectively and none for fourth or fifth place of
the peer group.
2011-2013 performance shares outcome
Measures
Total shareholder return
Reserves replacement
Strategic imperatives
Safety and operational risk management
Rebuilding external reputation
Staff alignment and morale
Overall outcome
Weight
50.0%
20.0%
30.0%
10.0%
10.0%
10.0%
Threshold
Outcomes
Max
Result %
of max
0%
70%
95%
80%
80%
39.5%
2013 outcomes
Overall, 39.5% of the shares awarded in the 2011-2013 plan are expected
to vest, based on results as shown in the table above.
Relative TSR was weighted heaviest, reflecting the high strategic priority
on restoring value. Outcomes failed to meet the threshold required and so
no shares vested for this measure.
Reserves replacement has been very positive and we expect that BP will
be in second place amongst the oil majors. Since the actual results of the
other majors are not publicly available until their respective annual reports
are published, the committee will review the outcomes when all
information is confirmed and decide then on the final vesting. For the
purposes of this report, and in accordance with UK regulations, second
place has been assumed. Any adjustment to this will be reported in next
year’s annual report on remuneration.
The committee’s review also concluded that progress against the three
strategic imperatives has been positive. S&OR management culture has
shown steady improvement and its high importance increasingly
embedded in the minds of employees, as demonstrated by our internal
surveys. Moreover the S&OR performance metrics have consistently
improved including against those of our peers. BP’s external reputation has
similarly shown steady improvement as measured by external surveys
assessing reputation amongst different groups in key countries. Finally,
staff alignment and morale has been reassuringly positive in the aftermath
of the Deepwater Horizon accident, with internal surveys demonstrating
improvements and a high scoring of measures related to group priorities
including safety and trust.
As in past years, the committee also considers the overall performance of
the company during the period and whether any other relevant factors
should be taken into account. Following this review, the committee
concluded that a 39.5% vesting was a fair reflection of overall performance
pending confirmation of the reserves replacement result. This will result in
the vesting as shown in the table below.
2011-2013 performance shares outcome
Bob Dudley
Iain Conn
Dr Brian Gilvary
Dr Byron Grote
Shares
awarded
1,330,332
Shares vested
inc dividends
596,028
Value of
vested shares
$4,521,866
623,025
90,000
654,498
283,920
£1,331,585
102,550
£504,509
293,232
$2,224,653
Dr Brian Gilvary’s vesting reflects awards granted prior to him joining the
board under equivalent plans below board level which have vested in early
2014. Dr Byron Grote’s award has been prorated to reflect his service prior
to retirement.
Information on performance shares awarded in early 2013, relating to the
2013-2015 period, was set out in last year’s report and a summary is
included in the table on page 85.
88
BP Annual Report and Form 20-F 2013
2014 implementation
Shares were awarded in early 2014 to a value of five and a half times salary
to Bob Dudley and four times salary to Iain Conn and Dr Brian Gilvary
(details of which are shown in the table on page 85). These have been
awarded under the performance share element of the executive directors’
incentive plan (EDIP) and are subject to a three-year performance period,
and for those shares that vest are subject, after tax, to an additional
three-year retention period.
The 2014-2016 performance share plan will be based on the same
measures as used last year and remain aligned directly with the company’s
strategic priorities and KPIs.
2014-2016 performance shares
Measures
KPI
Total shareholder return
Operating cash flow
Strategic imperatives
Safety and operational risk management
Reserves replacement ratio
Major project delivery
Weight
1/3rd
1/3rd
1/3rd
Link to strategy
Safe, reliable and compliant operations
Disciplined financial choices
Competitive project execution
Focus on high-value Upstream assets
Grow our exploration position
Build high-quality Downstream businesses
TSR and reserves replacement ratio will be assessed on a relative basis
compared with the other oil majors – Chevron, ExxonMobil, Shell and Total.
As set out in the policy report, commencing with the 2014-2016 plan,
vesting will be 100%, 80% and 25% for first, second and third place
respectively amongst the oil majors and no vesting for fourth or fifth place.
The committee has agreed targets and ranges for the other measures that
will be used to assess performance at the end of the three-year
performance period. As part of its overall assessment it also considers
whether, in the event of high levels of vesting, the result is consistent with
benefits achieved by shareholders. Full details are included in the policy
report. Pensions
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Pension
Framework
Executive directors are eligible to participate in company pension schemes
that apply in their home countries which follow national norms in terms of
structure and levels. Bob Dudley participates in the US plans (as did Dr
Byron Grote), and Iain Conn and Dr Brian Gilvary in the UK plan. Full details
on these plans are set out in the policy section of this report (page 103).
Bob Dudley (US)
Iain Conn (UK)
Brian Gilvary (UK)
Byron Grote (US)
Total accrued
pension at
31 Dec 2013
Additional
pension earned
during 2013
(net of inflation)
Actuarial value
of increase
earned
during 2013
20 times
increase
earned
during 2013
Service at
31 Dec 2013
34
28
27
n/a
$2,050
£326
£326
$1,416
(thousand)
$222
$1,319
$4,447
£2
£2
$7
£0
£0
-$93
£46
£44
$141
2013 outcomes
The table above sets out the change in pension for each of the executive
directors for 2013.
Bob Dudley’s pension increase is largely due to his promotion to group
chief executive in late 2010. Since his pension is based on three-year
average salary and bonus, the impact of a promotion takes a number of
years to be fully reflected in his pension. He is entitled, as all former
Amoco heritage employees, to receive the greater of the BP or Amoco
plans that apply. As part of the transition agreed at the time of merger, the
Amoco plan stopped accruing at the end of 2012, and therefore the BP
plan applicable to senior US executives will now determine his overall
accrued benefit. His total benefit under this plan is calculated as 1.3% of
final average earnings (including, for this purpose, base salary plus cash
bonus and bonus deferred into a compulsory or voluntary award under the
deferred matching element) for each year of service (without regard for tax
limits) which may be paid from various qualified and non-qualified plans as
described in the policy section of this report. The calculations in the above
table reflect this transition. The calculations also incorporate the latest
bonus reported on when determining the average of the best three
successive years’ bonus in the final average earnings calculation. Last
year’s numbers have been updated to be on a consistent basis.
Iain Conn and Dr Brian Gilvary participate in UK pension arrangements. The
disclosure of total pension includes any cash in lieu of additional accrual
that is paid to individuals in the UK scheme who have exceeded the annual
allowance or lifetime allowance under UK regulations. Both Iain Conn and
Dr Brian Gilvary fall into this category and in 2013 received cash
supplements of 35% of salary in lieu of future service accrual.
In terms of calculating the increase in pension value both a column on
20 times additional pension earned during the year as required by the new
UK regulations, as well as the actuarial value increase as previously
stipulated have been included in the table above. The summary table on
page 85 uses the 20 times additional pension earned figure and the cash
supplements are separately identified.
In Bob Dudley’s case, the committee has been informed by the company’s
consulting actuaries, Mercer, that the factor of 20 substantially overstates
the increase in value of his pension benefits primarily because his US
pension benefits are not subject to cost of living adjustments after
retirement, as they are in the UK. They have indicated that a typical annuity
factor for such US benefits is around 12, as compared to a UK plan where a
factor of 20 is often taken to reflect the increase in value of pension
benefits (as well as being required by UK regulations). Therefore the
committee considers that the actuarial value of increase identified in the
table above more accurately reflects the value of his pension increase.
89
BP Annual Report and Form 20-F 2013
Remuneration committee
The committee was made up of the following independent non-executive
directors:
Members
Antony Burgmans (chairman)
George David
Ian Davis
Professor Dame Ann Dowling
Carl-Henric Svanberg normally attends the meetings
Committee role
The committee’s tasks are formally set out in the board governance
principles as follows:
• To determine, on behalf of the board, the terms of engagement and
remuneration of the group chief executive and the executive directors
and to report on these to shareholders.
• To determine, on behalf of the board, matters of policy over which the
company has authority regarding the establishment or operation of the
company’s pension schemes of which the executive directors are
members.
• To nominate, on behalf of the board, any trustees (or directors of
corporate trustees) of such schemes.
• To review and approve the policies and actions being applied by the
group chief executive in remunerating senior executives other than
executive directors to ensure alignment and proportionality.
• To recommend to the board the quantum and structure of remuneration
for the chairman of the board.
Committee activities
During the year, the committee met six times. Key discussions and
decision items are shown in the table below.
Remuneration committee 2013 meetings
Jan Mar May
Jul
Sept Dec
Strategy and policy
Review and approve DRR for 2013 AGM
Consider DRR vote from 2013 AGM
Review impact of new UK regulations
Review policy
Review committee operation
Salary review
Executive directors
Executive team and group leaders
Annual bonus
Assess performance
Determine bonus for 2012
Review measures for 2014
Agree measures and targets for 2014
Long-term equity plans
Assess performance
Determine vesting of 2010-2012 plans
Agree awards for 2013-2015 plans
Review measures for 2014-2016 plans
Agree measures and targets for
2014-2016 plans
Other items
Review chairman's fees
Review major pension programmes
Other issues as required
90
The board’s overall evaluation process included a separate questionnaire
on the work of the remuneration committee. The results were analyzed by
an external consultant and discussed at the committee’s meeting in
January 2014. Processes continued to be rated as good to excellent and a
number of topics for more in-depth discussion were identified.
Independence and advice
Independence
The committee operates with a high level of independence. The board
considers all committee members to be independent with no personal
financial interest, other than as shareholders, in the committee’s decisions.
Consultation
The group chief executive is consulted on the remuneration of the other
executive directors and senior executives and on matters relating to the
performance of the company; neither he nor the chairman of the board
participate in decisions on their own remuneration. Both the group human
resources director and head of group reward may attend relevant sections
of meetings to ensure appropriate input on matters related to executives
below board level.
The committee consults other relevant committees of the board, for
example the SEEAC, on issues relating to the exercise of its judgement or
discretion.
Advice
Gerrit Aronson, an independent consultant, is the committee’s
independent adviser. He is engaged directly by the committee. Mr
Aronson acts as the secretary to the remuneration committee and advises
the chairman, the board and the nomination committee on a variety of
governance issues.
During 2013, advice to the committee was received from David Jackson,
the company secretary, who is employed by the company and who reports
to the chairman of the board. The company secretary periodically reviews
the independence of the advisers. Advice and services on particular
remuneration matters was received from other external advisers appointed
by the committee.
Towers Watson provided information on the global remuneration
market, principally for benchmarking purposes. Freshfields Bruckhaus
Deringer LLP provided legal advice on specific compliance matters to the
committee. Both firms provide other advice in their respective areas to the
group.
Total fees or other charges (based on an hourly rate) paid in 2013 to the
above advisers for the provision of remuneration advice to the committee
as set out above (save in respect of legal advice) is as follows:
Gerrit Aronson £150,000
Towers Watson £85,000
Shareholder engagement
The committee values its dialogue with major shareholders on
remuneration matters. During the year the committee’s chairman and the
committee’s independent adviser held individual meetings with
shareholders holding in aggregate more than 20% of the company’s shares
to ascertain their views and discuss important aspects of the committee’s
policy. They also met key proxy advisers. These meetings supplemented a
group meeting of shareholders with all committee chairs and the chairman,
as well as an investor relations programme including a regular ongoing
dialogue between the chairman and shareholders. This engagement
provides the committee with an important and direct perspective of
shareholder interests and, together with the voting results on the Directors’
remuneration report at the AGM, is considered when making decisions.
The committee reviewed remuneration policy during 2013 and, following
dialogue with shareholders, made three adjustments to further reinforce
our bias towards the long term and sustained performance.
First, a three-year retention period has been introduced to the matched
shares that vest in the deferred bonus element.
BP Annual Report and Form 20-F 2013 Second, a more stringent vesting schedule has been introduced for those
metrics in the performance share plan that are based on performance
relative to the other oil majors.
Third, a specific review of performance share plan outcomes will take
place to ensure high levels of vesting are consistent with shareholder
benefits. These are explained in more detail in the policy report.
The shareholder vote from the 2013 AGM is shown below. Total votes
withheld represent less than 1% of total shares outstanding.
2013 AGM directors’ remuneration report vote results
Year
2013
% vote ‘for’ % vote ‘against’
94.1%
Votes withheld
5.9% 108,843,360
Directors’ shareholdings
Executive directors are required to develop a personal shareholding of five
times salary within a reasonable period of time from appointment. It is the
stated intention of the policy that executive directors build this level of
personal shareholding primarily by retaining those shares that vest in the
deferred bonus and performance share plans which are part of the EDIP.
In assessing whether the requirement has been met, the committee takes
account of the factors it considers appropriate, including promotions and
vesting levels of these share plans, as well as any abnormal share price
fluctuations. The table below shows the status of each of the executive
directors in developing this level. These figures include the value as at
24 February 2014 from the directors’ interests shown below plus the
assumed vesting of the 2011-2013 performance shares and is consistent
with the figures reported in the single figure table on page 85.
Bob Dudley
Iain Conn
Appointment date
October 2010
Value of current
shareholding
$5,477,092
July 2004
£3,888,423
Dr Brian Gilvary
January 2012
£2,502,388
% of policy
achieved
61%
101%
71%
The committee is satisfied that all executive directors comply with the
policy by building the required personal shareholding in a reasonable period
of time following their appointment. Importantly, none of the existing
executive directors has sold shares that vested from the EDIP.
Directors’ interests
The figures below indicate and include all the beneficial and non-beneficial
interests of each executive director of the company in shares of BP (or
calculated equivalents) that have been disclosed to the company under the
Disclosure and Transparency Rules (DTRs) as at the applicable dates.
Ordinary
shares or
equivalents at
1 Jan 2013
346,008a
509,729b
331,977
Ordinary
shares or
equivalents at
31 Dec 2013
355,707a
600,272b
412,973
At 1 Jan 2013 At retirement
1,512,616c 1,512,616d
Change from
31 Dec 2013
to
24 Feb 2014
–
26,231
81,570
Ordinary
shares or
equivalents
total at
24 Feb 2014
355,707a
626,503b
494,543
–
–
Bob Dudley
Iain Conn
Dr Brian Gilvary
Former executive director
Dr Byron Grote
a Held as ADSs.
b Includes 48,024 shares held as ADSs.
c Held as ADSs, except for 94 shares held as ordinary shares.
d On retirement at 11 April 2013.
The following table shows both the performance shares and the deferred
bonus element awarded under the EDIP. These figures represent the
maximum possible vesting levels. The actual number of shares/ADSs that
vest will depend on the extent to which performance conditions have been
satisfied over a three-year period. Additional details regarding the deferred
bonus and performance shares elements of the EDIP awarded can be
found on pages 93 and 94.
Change from
31 Dec 2013
to
24 Feb 2014
Performance
shares at
1 Jan 2013
Performance
shares at
31 Dec 2013
Performance
shares total at
24 Feb 2014
3,691,950 4,953,654 1,604,178 6,557,832
818,486 3,484,800
2,305,847 2,666,314
776,350 2,375,957
669,434 1,599,607
Performance
shares at
1 Jan 2013
Performance
shares at
31 Dec 2013
2,889,192 1,810,686c
Change from
31 Dec 2013
to
24 Feb 2014
–
Performance
shares total at
24 Feb 2014
–
Bob Dudleya
Iain Conn
Dr Brian Gilvaryb
Former executive director
Dr Byron Grotea
a Held as ADSs.
b This includes conditionally awarded shares made under the competitive performance plan prior to
his appointment as a director. The vesting of these shares is subject to performance conditions.
c On retirement at 11 April 2013.
At 24 February 2014, the following directors held the numbers of options
under the BP group share option schemes over ordinary shares or their
calculated equivalent, and the number of restricted shares as set out
below. None of these are subject to performance conditions. Additional
details regarding these options can be found on page 94.
Bob Dudley
Iain Conn
Dr Brian Gilvary
Former executive director
Dr Byron Grote
Options
–
3,814
504,191
Options
–
Restricted
shares
–
–
80,335
Restricted
shares
–
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.
There are no directors or members of senior management who own more
than 1% of the ordinary shares in issue. At 24 February 2014, all directors
and senior management as a group held interests of 9,632,638 ordinary
shares or their calculated equivalent, 12,418,589 performance shares or
their calculated equivalent and 6,058,172 options over ordinary shares or
their calculated equivalent under the BP group share option schemes.
Executive director leaving the board
Dr Byron Grote retired from the board at the 2013 AGM and after a
transition period, retired from the company at the end of June 2013. The
terms of his departure were reported last year but are reiterated here for
completeness. Under the rules of the EDIP, his outstanding performance
share awards pertaining to 2011-2013, 2012-2014, and 2013-2015
performance periods, as well as the matching share awards in respect of
the 2010, 2011 and 2012 deferred bonus have been prorated to reflect
actual service during the applicable three-year performance periods. These
share awards will vest at the normal time to the extent the performance
targets or hurdles have been met. His 2013 bonus eligibility was likewise
prorated to reflect his service and based on group results for the year. He
has not received any termination payments on leaving service.
91
Corporate governanceBP Annual Report and Form 20-F 2013 Relative importance of spend on pay
Key expenditure areas
Remuneration paid to all
employeesa
Distributions to shareholders (total)
Dividendsb
Buybacksc
Capital investmentd
2013
(million)
2012
(million)
$13,654
$12,404
$6,911
$5,463
$13,448
$6,276
$6,276
$0
% change
1.5%
97.6%
$24,600
$23,950
2.7%
a Total remuneration reflects overall employee costs. See Financial statements – Note 33 for
further information.
b Dividends includes both scrip dividends as well as those paid in cash. See Financial statements
– Note 12 for further information.
c See Financial statements – Note 31 for further information.
d Capital investment reflects organic capital expenditure. See footnote d on page 236 for further
information.
Percentage change in CEO remuneration
Comparing 2013 to 2012
% Change in CEO remuneration
Salary
Benefits
2.8% 4.7%
Bonus
40%
% Change in comparator group
remunerationa
3.3%
0%b
30%
a The comparator group comprises some 40% of BP’s global employee population being
professional/managerial grades of employees based in the UK and US and employed on more
readily comparable terms.
b There was no change in employee benefits level overall. Those benefits that are linked to salary
have changed in line with base salary increases.
Remuneration statistics and comparisons
The information below is provided according to the requirements and
definitions included in UK regulations.
Historical TSR performance
Historical TSR performance
FTSE 100
BP
£200
£150
£100
£50
i
g
n
d
o
h
l
0
0
1
£
l
a
c
i
t
e
h
t
o
p
y
h
f
o
e
u
a
V
l
2008
2009
2010
2011
2012
2013
This graph shows the growth in value of a hypothetical £100 holding in
BP p.l.c. ordinary shares over five years, relative to the FTSE 100 Index of
which the company is a constituent. The values of the hypothetical £100
holdings at the end of the five-year period were £117.33 and £188.41
respectively.
History of CEO remuneration
Year
2009
2010c
2011
2012
2013
CEO
Hayward
Hayward
Dudley
Dudley
Dudley
Dudley
Total
remuneration
(thousand)a
£6,753
£3,890
$7,722
$8,312
$9,184
$13,179
Annual bonus
% of
maximum
89%b
0%
0%
67%
65%
88%
Performance
share vesting
% of maximum
17.5%
0%
0%
16.7%
0%
39.5%
a Total remuneration figures include pension and are shown as reported each year in the
respective directors’ remuneration report with the exception of 2012 which is restated in line with
the figure reported in the single figure table in this report.
b 2009 annual bonus did not have an absolute maximum and so is shown as a percentage of the
maximum established in 2010.
c 2010 figures show full year total remuneration for both Hayward and Dudley, although Dudley
did not become CEO until October 2010.
92
BP Annual Report and Form 20-F 2013
Further details
Deferred shares (audited)a
Bonus year
Type
Performance
period
Date of award of
deferred shares
At 1 Jan
2013
Awarded
2013
At 31 Dec
2013
Awarded
2014
Potential maximum deferred shares
Number of
ordinary
shares
vested
Face value
of the award
at date of
grant £
Vesting date
Deferred share element interests
Interests vested in 2013 and 2014
Bob Dudleyb
2011c
Iain Conn
Dr Brian Gilvary
2012d
2013d
2010
2011c
2012d
2013d
2009
2010
2011h
2012d
2013d
Former executive director
Dr Byron Groteb
2010
2011c
2012d
2012-2014
Comp
2012-2014
Vol
2012-2014
Mat
2013-2015
Comp
2013-2015
Vol
2013-2015
Mat
2014-2016
Comp
2014-2016
Mat
2011-2013
Comp
2011-2013
Mat
2012-2014
Comp
2012-2014
Vol
2012-2014
Mat
2013-2015
Comp
2013-2015
Vol
2013-2015
Mat
2014-2016
Comp
Mat
2014-2016
DABe 2010-2012
DABe 2011-2013
DABe 2012-2014
2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
Comp
Vol
Mat
Comp
Mat
Comp
Vol
Mat
Comp
Vol
Mat
Comp
Vol
Mat
2011-2013
2011-2013
2011-2013
2012-2014
2012-2014
2012-2014
2013-2015
2013-2015
2013-2015
08 Mar 2012
08 Mar 2012
08 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
09 Mar 2011
09 Mar 2011
08 Mar 2012
08 Mar 2012
08 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
15 Mar 2010
14 Mar 2011
15 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
09 Mar 2011
09 Mar 2011
09 Mar 2011
08 Mar 2012
08 Mar 2012
08 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
109,206
109,206
218,412
–
–
–
– 114,690
– 114,690
– 229,380
–
–
–
–
–
21,384
–
21,384
–
80,652
–
80,652
161,304
–
80,648
–
–
80,648
– 161,296
–
–
–
–
–
87,394
–
44,971
–
73,624
78,815
–
–
78,815
– 157,630
–
–
–
–
–
26,604
–
26,604
–
53,208
–
91,638
–
91,638
–
183,276
97,278
–
–
97,278
– 194,556
109,206
109,206
218,412
114,690
114,690
229,380
–
–
21,384
21,384
80,652
80,652
161,304
80,648
80,648
161,296
–
–
–
44,971
73,624
78,815
78,815
157,630
–
–
26,604
26,604
44,340i
91,638
91,638
91,638i
97,278
97,278
32,424i
–
–
–
–
–
–
149,628
149,628
–
–
–
–
–
–
–
–
100,563
100,563
–
–
–
–
–
–
96,653
96,653
–
–
–
–
–
–
–
–
539,478
–
539,478
–
– 1,078,955
521,840
–
–
521,840
– 1,043,679
728,688
–
728,688
–
24,670f 12 Feb 2014
–
24,670f 12 Feb 2014
–
398,421
–
398,421
–
796,842
–
366,948
–
366,948
–
733,897
–
489,742
–
489,742
–
95,279f 15 Jan 2013
–
51,118f 09 Jan 2014
–
362,966
–
358,608
–
358,608
–
717,217
–
470,700
–
470,700
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
30,174f 12 Feb 2014
30,174f 12 Feb 2014
50,292f 12 Feb 2014
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
452,692
452,692
452,692
442,615
442,615
147,529
Comp = Compulsory.
Vol = Voluntary.
Mat = Matching.
DAB = Deferred annual bonus plan.
a Since 2010, vesting of the deferred shares has been subject to a safety and environmental sustainability hurdle, and this will continue. If the committee assesses that there has been a material
deterioration in safety and environmental performance, or there have been major incidents, either of which reveal underlying weaknesses in safety and environmental management, then it may
conclude that shares should vest only in part, or not at all. In reaching its conclusion, the committee will obtain advice from the SEEAC. There is no identified minimum vesting threshold level.
b Bob Dudley and Dr Byron Grote received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares.
c The face value has been calculated using the market price of ordinary shares on 8 March 2012 of £4.94.
d The market price at closing of ordinary shares on 11 February 2013 was £4.55 and for ADSs was $43.01 and on 12 February 2014 was £4.87 and for ADSs was $48.38. The sterling value has been
used to calculate the face value.
e Dr Brian Gilvary was granted the shares under the DAB prior to his appointment as a director. The vesting of these shares is not subject to further performance conditions and he receives deferred
shares at each scrip payment date as part of his election choice.
f The market price of each share used to determine the total value at vesting on the vesting dates of 15 January 2013, 9 January 2014 and 12 February 2014 were £4.58, £4.97 and £4.90 respectively
and for ADSs on 12 February 2014 was $48.41.
h The face value has been calculated using the market price of ordinary shares on 15 March 2012 of £4.93.
i All deferred and matched shares have been prorated to reflect actual service during the performance period and these figures have been used to calculate the face value.
93
Corporate governanceBP Annual Report and Form 20-F 2013 Performance shares (audited)
Share element interests
Interests vested in 2013 and 2014
Bob Dudleyb
Iain Conn
Dr Brian Gilvary
Potential maximum performance sharesa
Performance
period
2010-2012
2011-2013
2012-2014d
2013-2015d
2014-2016d
2008-2013e
2010-2012
2011-2013
2012-2014d
2013-2015d
2014-2016d
2010-2012f
2011-2013f
2010-2012g
2011-2013g
2012-2014d
2013-2015d
2014-2016d
Date of award of
performance shares
09 Feb 2010
09 Mar 2011
08 Mar 2012
11 Feb 2013
12 Feb 2014
13 Feb 2008
09 Feb 2010
09 Mar 2011
08 Mar 2012
11 Feb 2013
12 Feb 2014
15 Mar 2010
14 Mar 2011
15 Mar 2010
14 Mar 2011
08 Mar 2012
11 Feb 2013
12 Feb 2014
At 1 Jan
2013
581,082
1,330,332
1,343,712
–
–
133,452
656,813
623,025
660,633
–
–
60,000
67,500
22,500
22,500
624,434
–
–
Awarded
2013
–
–
–
1,384,026
–
–
–
–
–
694,688
–
–
–
–
–
–
637,413
–
At 31 Dec
2013
–
1,330,332
1,343,712
1,384,026
–
–
–
623,025
660,633
694,688
–
–
67,500
–
22,500
624,434
637,413
–
Awarded
2014
–
–
–
–
1,304,922
–
–
–
–
–
660,128
–
–
–
–
–
–
605,544
Number of
ordinary
shares
vested
0
–
–
–
145,489
0
Vesting date
–
596,028c March 2014
–
–
–
07 Feb 2013
–
283,920 March 2014
–
–
–
15 Jan 2013
09 Jan 2014
–
06 Feb 2014
–
–
–
–
–
–
65,414c
76,726c
0
25,824c
–
–
–
Face value
of the
award £
–
–
6,637,937
6,297,318
6,354,970
–
–
–
3,263,527
3,160,830
3,214,823
–
–
–
–
3,084,704
2,900,229
2,948,999
Former executive directors
Dr Anthony Hayward
Andrew Inglis
Dr Byron Groteb
2010-2012
2010-2012
2010-2012
2011-2013
2012-2014d
2013-2015d
–
–
–
–
–
853,650
a For awards under the 2010-2012 plan, performance conditions were measured one-third on TSR against ExxonMobil, Shell, Total, ConocoPhillips and Chevron and two-thirds on a balanced scorecard
of underlying performance. For awards under the 2011-2013 plan, performance conditions are measured 50% on TSR against ExxonMobil, Shell, Total and Chevron; 20% on reserves replacement
against the same peer group; and 30% against a balanced scorecard of strategic imperatives. For awards under the 2012-2014, 2013-2015 and 2014-2016 plans, performance conditions are
measured one-third on TSR against ExxonMobil, Shell, Total and Chevron; one-third on operating cash flow; and one-third on a balanced scorecard of strategic imperatives. Each performance period
ends on 31 December of the third year. There is no identified overall minimum vesting threshold level but to comply with UK regulations a value of 30%, which is conditional on the TSR, reserves
replacement ratio and one of the strategic imperatives reaching the minimum threshold, has been calculated.
–
–
–
293,232c March 2014
–
–
09 Feb 2010
09 Feb 2010
09 Feb 2010
09 Mar 2011
08 Mar 2012
11 Feb 2013
–
–
–
–
2,047,472
647,365
–
–
–
654,498h
414,468h
142,278h
303,948h
218,938h
801,894
785,394
828,936
–
–
–
–
–
–
–
0
0
0
–
–
b Bob Dudley and Dr Byron Grote received awards in the form of ADSs. The above numbers reflect calculated equivalents in ordinary shares. One ADS is equivalent to six ordinary shares.
c Represents vestings of shares made at the end of the relevant performance period based on performance achieved under rules of the plan and includes reinvested dividends on the shares vested.
The market price of each share at the vesting date of 15 January 2013 was £4.58, at 9 January 2014 was £4.97 and at 6 February 2014 was £4.77. For the assumed vestings dated March 2014 a
price of £4.69 per ordinary share and $45.52 per ADS has been used. These are the average prices from the fourth quarter of 2013.
d The market price at closing of ordinary shares on 8 March 2012 was £4.94, on 11 February 2013 was £4.55 and for ADSs was $43.01 and on 12 February 2014 was £4.87 and for ADSs was $48.38.
The sterling value has been used to calculate the face value.
e Restricted award under share element of EDIP. As reported in the 2007 directors’ remuneration report in February 2008, the committee awarded Iain Conn restricted shares, in two tranches of
133,452 shares each and on vesting include re-invested dividends on the shares vested. The total vesting of the first tranche was 155,695 shares at £4.91 on 22 February 2011. The remaining award,
noted above, vested on 7 February 2013, the fifth anniversary of the award at £4.58.
f Dr Brian Gilvary was conditionally awarded shares under the Executive Performance Plan prior to his appointment as a director. The vesting of these shares is not subject to further performance
conditions.
g Dr Brian Gilvary was conditionally awarded shares under the Competitive Performance Plan prior to his appointment as a director. The vesting of these shares is subject to performance conditions.
h Potential maximum of performance shares element have been pro-rated to reflect actual service during the performance period and these figures have been used to calculate the face value as
appropriate.
Share interests in share option plans (audited)
Dr Brian Gilvary
Bob Dudleya
Iain Conn
Option type
BP SOP
SAYE
SAYE
SAYE
BP 2011
SAYE
At 1 Jan 2013
17,835
605
3,017
797
500,000
4,191
The closing market prices of an ordinary share and of an ADS on 31 December 2013 were £4.88 and $48.61 respectively.
During 2013 the highest market prices were £4.93 and $48.61 respectively and the lowest market prices were £4.31 and $40.19 respectively.
BP SOP = BP Share Option Plan. These options were granted to Bob Dudley prior to his appointment as a director and are not subject to performance conditions.
BP 2011 = BP 2011 Plan. These options were granted to Dr Brian Gilvary prior to his appointment as a director and are not subject to performance conditions.
SAYE = Save As You Earn all employee share scheme.
a Numbers shown are ADSs under option. One ADS is equivalent to six ordinary shares.
b Options exercised on 6 February 2013. Market price at closing for information. Shares were sold in tranches after the exercise of options at an average price of $43.62 per ADS.
c Options exercised on 13 February 2013. Market price at closing for information. Shares were retained after the exercise of options.
Exercised At 31 Dec 2013
17,835b
–
605c
–
3,017
–
797
–
500,000
–
4,191
–
Option price
$38.10
£4.20
£3.68
£3.16
£3.72
£3.68
Granted
–
–
–
–
–
–
Market price at
date of exercise
$43.99
£4.54
–
–
–
–
Date from which
first exercisable
17 Feb 2006
01 Sep 2012
01 Sep 2016
01 Sep 2015
07 Sep 2014
01 Sep 2016
Expiry date
16 Feb 2013
28 Feb 2013
28 Feb 2017
28 Feb 2016
07 Sep 2021
28 Feb 2017
94
BP Annual Report and Form 20-F 2013 (b) Non-executive directors
The table below shows the fees paid for non-executive directors for the
years ended 31 December 2012 and 31 December 2013:
This section of the directors’ remuneration report completes the directors’
annual report on remuneration with details for non-executive directors.
2013 remuneration (audited)
All fees in £ thousand
Carl-Henric Svanberg
Paul Anderson
Admiral Frank Bowman
Antony Burgmans
Cynthia Carroll
George Davidb
Ian Davis
Professor Dame Ann Dowlingc
Brendan Nelson
Phuthuma Nhleko
Andrew Shilston
2013
773a
175
165
145
120
185
150
140
130
150
150
Total fees
2012
750
149
126
120
98
135
128
97
119
123
125
a The chairman received a further £49,000 by way of taxable benefits.
b In addition, George David received £12,500 for chairing the BP technology advisory council until
1 July 2013.
c In addition, Professor Dowling received £25,000 for chairing and being a member of the BP
technology advisory council and £3,000 for an ad hoc technology advisory council meeting fee.
There were no changes following the review of non-executive
remuneration undertaken in 2012 which benchmarked the structure and
fees of BP non-executive directors against the 10 largest companies by
market capitalization in the FTSE100. In March 2013 it was agreed that the
chairman’s fee would be increased from 1 May 2013. There are no
changes proposed to the implementation of the policy for non-executive
directors and the chairman for 2014.
Fee structure
The table below shows the fee structure for non-executive directors from
1 May 2013:
Chairmana
Senior independent directorb
Board member
Audit, Gulf of Mexico, remuneration
and SEEA chairmanship feesc
Committee membership feed
Intercontinental travel allowance
Fee level
£ thousand
785
120
90
30
20
5
a The chairman is ineligible for committee chairmanship and membership fees or intercontinental
travel allowance. He has the use of a fully maintained office for company business, a chauffeured
car and security advice in London. He receives secretarial support as appropriate to his needs in
Sweden.
b The senior independent director is eligible for committee chairmanship fees and intercontinental
travel allowance plus any committee membership fees.
c Committee chairmen do not receive an additional membership fee for the committee they chair.
d For members of the audit, Gulf of Mexico, SEEA and remuneration committees.
Non-executive director interests
The figures below indicate and include all the beneficial and non-beneficial interests of each non-executive director of the company in shares of BP (or
calculated equivalents) that have been disclosed to the company under the DTRs as at the applicable dates.
Current non-executive directors
Carl-Henric Svanberg
Paul Anderson
Admiral Frank Bowman
Antony Burgmans
Cynthia Carroll
George David
Ian Davis
Professor Dame Ann Dowling
Brendan Nelson
Phuthuma Nhleko
Andrew Shilston
a Held as ADSs.
Ordinary shares
or equivalents at
1 Jan 2013
988,077
6,000a
16,320a
10,156
10,500a
579,000a
10,866
11,630
11,040
–
15,000
Ordinary shares
or equivalents at
31 Dec 2013
1,039,276
30,000a
16,320a
10,156
10,500a
579,000a
11,449
22,320
11,040
–
15,000
Change from
31 Dec 2013 to
24 Feb 2014
–
–
–
–
–
–
–
–
–
–
–
Ordinary shares
or equivalents
total at 24 Feb
2014
1,039,276
30,000a
16,320a
10,156
10,500a
Value of current
shareholding
£5,258,737
$251,350
$136,734
£51,389
$87,973
579,000a $4,851,055
£57,932
11,449
£112,939
22,320
£55,862
11,040
–
–
£75,900
15,000
% of policy
achieved
670
168
91
57
59
3,241
64
125
62
0
63
Past directors
Sir Ian Prosser (who retired as a non-executive director of BP in April 2010)
was appointed as a director and non-executive chairman of BP Pension
Trustees Limited on 1 October 2010. During 2013, he received £100,000
for this role.
Peter Sutherland (who was chairman of BP until 31 December 2009)
continued his membership of the BP international advisory board after his
retirement from the board of BP p.l.c. During 2013, he received €100,000
for this role.
95
Corporate governanceBP Annual Report and Form 20-F 2013
Directors’ remuneration policy
The following pages set out the remuneration policy
for directors of BP p.l.c., which, if approved by
shareholders at the AGM on 10 April 2014, will take
effect from the date of that meeting.
The policy is divided into separate sections for
executive and non-executive directors. The
remuneration of the executive directors is set by the
remuneration committee (the committee) under
delegated powers from the board. The committee
makes a recommendation to the board for the
remuneration of the chairman. The remuneration of
the non-executive directors is set by the board
based on a recommendation from the chairman, the
group chief executive and the company secretary.
(a) Executive directors
Introduction
Remuneration policy table
96
96
98
100 Remuneration policy in more depth
100
100
101
102
103
Salary and benefits
Annual bonus
Deferred bonus
Performance shares
Pension
104 Scenario charts
105 Recruitment
105 Service contracts
105 Exit payments
106 External appointments
107
(b) Non-executive directors
(a) Executive directors
Introduction
The remuneration policy for the executive directors and the decisions of
the remuneration committee have been consistently guided by six key
principles. These principles were introduced more than 10 years ago and
have been described in all remuneration reports to shareholders since
then.
Key principles
The principles represent the overarching approach of the board and the
committee to the remuneration of the executive directors.
Fair treatment: Total overall pay takes account of both the external market
and company conditions to achieve a balanced, ‘fair’ outcome.
Shareholder engagement: The remuneration committee actively seeks
to understand shareholder preferences and be transparent in explaining its
policy and decisions.
The aim of this policy is to ensure that executive directors are remunerated
in a way that reflects the company’s long-term strategy. Consistent with
this, a high proportion of directors’ total potential remuneration has been,
and will be, strongly linked to the company’s long-term performance.
Linked to strategy: A substantial proportion of executive director
remuneration is linked to success in implementing the company’s strategy.
Performance related: The major part of total remuneration varies with
performance, with the largest elements being share based, further aligning
with shareholders’ interests.
Long term: The structure of pay is designed to reflect the long-term
nature of BP’s business and the significance of safety and environmental
risks.
Informed judgement: There are quantitative and qualitative assessments
of performance with the remuneration committee making informed
judgement within a framework approved by shareholders.
96
BP Annual Report and Form 20-F 2013
Implementation matters
This policy is a forward-looking document, but it is a requirement of the
regulations that, if obligations under the company’s previous remuneration
policy are to remain in force, these must be stated and certain information
must be provided. In view of the long-term nature of BP’s remuneration
structures – including obligations under service contracts, pension
arrangements, the executive directors’ incentive plan (EDIP) and other
incentive awards – a substantial number of pre-existing obligations will
remain outstanding at the time that this policy is approved, including
obligations that are ‘grandfathered’ by virtue of being in force at
27 June 2012. It is the company’s policy to honour in full any pre-existing
obligations that have been entered into prior to the effective date of
this policy.
Finally the new regulations require detailed information on performance
measures and targets to be included in the report unless the directors
consider that information to be commercially sensitive. The directors are
committed to full and transparent disclosure to shareholders and will seek
to provide the information wherever possible. However, the directors have
determined that the current targets for short- and long-term incentives are
commercially sensitive and should not be disclosed at the commencement
of any relevant performance period as they believe this is not in the
interests of the company. The directors will review such targets at the end
of each relevant performance period and determine whether any target
may be disclosed.
Executive directors’ incentive plan
The EDIP was first approved by shareholders in April 2000 and has since
provided the umbrella framework for share based remuneration for
executive directors. With the introduction of the new UK regulations on pay
reporting, the prime shareholder approval for all elements of remuneration
policy, including share based elements, will now be via the policy report.
The EDIP will continue to provide the vehicle to implement the share based
elements of policy that have been approved by shareholders, the EDIP will
continue to require a separate shareholder approval under UK Listing Rules,
and its renewal has been brought forward to the 2014 AGM to coincide
with the approval of this remuneration policy. Given the duplication of the
two regulatory regimes, the remuneration committee will ensure that any
actions taken in future under the EDIP will be consistent with the policy
approved by shareholders.
Flexibility, judgement and discretion
The committee is empowered to undertake quantitative and qualitative
assessments of performance in reaching its decisions. This involves the
use of judgement and discretion within a framework that is approved by,
and transparent to, shareholders.
The committee considers that the powers of flexibility, judgement and
discretion are critical to successful design and implementation of the
remuneration policy. This approach is supported in the UK by the ABI’s
principles of remuneration and the GC100 and Investor Group’s guidance
on directors’ remuneration reporting.
In framing this policy, the committee has therefore taken care to ensure
that these existing and important powers are continued in the future.
• The committee considers that an effective remuneration policy needs
to be sufficiently flexible to take account of future changes in the
industry environment facing BP and in remuneration practice generally.
The policy is therefore sufficiently flexible so that the committee can
react to changed circumstances (for example in applying particular
performance measures within schemes which may need to evolve with
the strategy of the company), without the need for a specific
shareholder approval.
• The policy preserves the committee’s long-standing power to exercise
judgement in making a qualitative assessment in certain circumstances.
For annual or long-term bonus awards a number of metrics are used.
Many are numerical in nature and require a quantitative assessment.
Some will be qualitative, for example the maintenance or improvement
in the company’s reputation. Here an impartial assessment will
be required.
• This policy sets out various areas where the committee has discretion,
mainly where it is desirable to vary a formulaic outcome that would
otherwise arise from the policy’s implementation. The committee
considers that the ability to exercise discretion, upwards or downwards,
is important to ensure that a particular outcome is fair in light of the
director’s own performance and the company’s overall performance and
positioning under particular performance metrics. In accordance with UK
regulations, areas where the remuneration policy provides for the
exercise of discretion are identified in the report.
This policy sets out the areas where the committee wishes to have
flexibility or use discretion in its implementation. Each year, the committee
will report to shareholders on the use of these powers.
Key considerations
The committee considers a wide range of factors when developing the
remuneration policy for executive directors. The competitive market for top
executives both within the oil sector and broader industrial corporations
provides an important context. The committee believes that it has a duty to
shareholders to ensure that the company is competitive so as to attract
and retain the high calibre executives required to lead the company.
The committee also considers employment conditions within the company
when establishing and implementing policy for executive directors to
ensure alignment of principles and approach. In particular the committee
reviews the policy for the group leaders of around 500 top executives to
ensure that policy for both groups is aligned and reflects consistent
standards and approach.
Decisions regarding remuneration for employees outside the group leaders
are the responsibility of the group chief executive. Employees are not
consulted directly by the committee when making policy decisions
although feedback from employee surveys provide views on a wide range
of points including pay which are regularly reported to the board.
The committee has a long-standing and active programme of engaging
with key shareholders that includes one-on-one meetings with them each
year. This engagement programme complements the overall investor
relations and board engagement efforts of the company, and focuses
mainly on our largest shareholders and main proxy advisers. Feedback
from shareholders on executive director remuneration forms an important
component of the committee’s considerations when establishing policy.
97
Corporate governanceBP Annual Report and Form 20-F 2013
Remuneration policy table
Element and purpose
Salary and benefits
Provides base-level fixed remuneration
to reflect the scale and dynamics of the
business, and to be competitive with the
external market.
See page 100.
Annual bonus
Provides a variable level of remuneration
dependent on short-term performance
against the annual plan.
See page 100.
Deferred bonus
Reinforces the long-term nature of
the business and the importance of
sustainability, linking a further part
of remuneration to equity.
See page 101.
Performance shares
Ties the largest part of remuneration to
long-term performance. The level varies
according to performance relative to
measures linked directly to strategic
priorities.
See page 102.
Operation and opportunity
Performance framework
Changes to policy
• Salaries are normally set in the home
currency of the executive director and
reviewed annually.
• Salary levels and total remuneration of oil
and other top European multinationals, and
related US corporations, are considered by
the committee. Internally, increases for the
group leaders as well as all employees in
relevant countries are considered.
• Salary increases will be in line with all
employee increases in the UK and US and
limited to within 2% of average increase for
the group leaders.
• Benefits reflect home country norms.
The current package of benefits will be
maintained, although the taxable value
may fluctuate.
• Total overall bonus (before any deferral) is
based on performance relative to measures
and targets reflected in the annual plan,
which in turn reflects BP’s strategy.
• On-target bonus is 150% of salary with
225% as maximum.
• Achieving annual plan objectives equates
to on-target bonus. The level of threshold
payout for minimum performance varies
according to the nature of the measure
in question.
• A third of the annual bonus is required to be
deferred and up to a further third can be
deferred voluntarily. This deferred bonus is
awarded in shares.
• Deferred shares are matched on a one-for-
one basis, and both deferred and matched
shares vest after three years depending on
an assessment by the committee of safety
and environmental sustainability over the
three-year period.
• Where shares vest, additional shares
representing the value of reinvested
dividends are added.
• Before being released, all matched shares
that vest after the three-year performance
period are subject (after tax) to an additional
three-year retention period.
• Shares up to a maximum value of five and
a half times salary for the group chief
executive and four times salary for the other
executive directors can be awarded annually.
• Vesting of shares after three years is
dependent on performance relative to
measures and targets reflecting BP’s
strategy.
• Where shares vest, additional shares
representing the value of reinvested
dividends are added.
• Before being released, those shares that
vest after the three-year performance period
are subject (after tax) to an additional
three-year retention period.
Pension
Recognizes competitive practice
in home country.
See page 103.
• Executive directors participate in the
company pension schemes that apply in
their home country.
• Current UK executive directors remain on a
defined benefit pension plan and receive a
cash supplement of 35% of salary in lieu of
future service accrual when they exceed the
annual allowance set by legislation.
• Current US executive directors participate in
transition arrangements related to heritage
plans of Amoco and Arco and normal
defined benefit plans that apply to
executives with an accrual rate of 1.3% of
final earnings (salary plus bonus) for each
year of service.
Note: Further information is set out in the accompanying notes which follow this table.
98
BP Annual Report and Form 20-F 2013
Element and purpose
Operation and opportunity
Performance framework
• Salary increases are not directly linked to
performance. However a base-line level of
personal contribution is needed in order to be
considered for a salary increase and exceptional
sustained contribution may be grounds for
accelerated salary increases.
Changes to policy
No change to policy.
• Specific measures and targets are determined
each year by the remuneration committee.
• A proportion will be based on safety and
operational risk management and is likely to
include measures such as loss of primary
containment, recordable injury frequency and
tier 1 process safety events.
• The principal measures of annual bonus will be
No change to policy.
based on value creation and may include financial
measures such as operating cash flow,
replacement cost operating profit and cost
management, as well as operating measures
such as major project delivery, Downstream net
income per barrel and Upstream unplanned
deferrals. The specific metrics chosen each year
will be set out and explained in the annual report
on remuneration.
• Both deferred and matched shares must
pass an additional hurdle related to safety and
environmental sustainability performance in
order to vest.
• If there has been a material deterioration in
safety and environmental metrics, or there have
been major incidents revealing underlying
weaknesses in safety and environmental
management then the committee, with advice
from the safety, ethics and environmental
assurance committee, may conclude that shares
vest in part, or not at all.
• All deferred shares are subject to clawback
provisions if they are found to have been granted
on the basis of materially misstated financial or
other data.
Introduction of an additional three-year
retention period on matched shares that
vest. This results in a six-year plan, the
same as for performance shares.
• Performance shares will vest on the following
three performance measures:
– Total shareholder return relative to other
oil majors.
– Operating cash flow.
– Strategic imperatives.
• Measures based on relative performance to oil
majors will vest 100%, 80%, 25% for first,
second and third place finish respectively and
0% for fourth or fifth position.
• Pension in the UK is not directly linked to
performance.
• Pension in the US includes bonus in determining
benefit level.
• The committee identifies the specific strategic
imperatives to be included every year and may
also alter the other measures if others are
deemed to be more aligned to strategic priorities.
These are explained in the annual report on
remuneration.
• The committee may exercise judgement to adjust
vesting outcomes if it concludes that the formulaic
approach does not reflect the true underlying
performance of the company’s business or is
inconsistent with shareholder benefits.
• All performance shares are subject to clawback
provisions if they are found to have been granted
on the basis of materially misstated financial or
other data.
Override provision extended requiring
high levels of vesting to be consistent
with shareholder benefit.
More stringent vesting schedule for
those metrics that are measured on
performance relative to the other four
oil majors. Third place finish reduced
from 35% to 25% and second place
increased from 70% to 80%.
No change to policy.
99
Corporate governanceBP Annual Report and Form 20-F 2013 Remuneration policy in more depth
Salary and benefits
At 1 January 2014, the annual salaries for executive directors were as follows:
Bob Dudley $1,800,000, Iain Conn £774,000 and Dr Brian Gilvary £710,000.
Most components of total remuneration are determined as multiples of
salary and so the committee reviews salaries, normally annually.
These reviews consider both external competitiveness and internal
consistency when determining if any increases should be applied.
Salaries are compared against other oil majors, but the committee also
monitors market practice among European and US companies of a similar
size, geographic spread and business dynamic to BP.
Salaries are normally set in the home currency of the executive director.
The levels of increase for all our employees in relevant countries, as well as
the profile of increases for group leaders, are reviewed and considered
when assessing executive director salary increases.
The committee would expect annual increases to be in line with all
employee increases in the UK and US, unless there are promotions or
significant changes in responsibilities, in which case they would retain the
flexibility to recognize these with appropriate salary increases but will be
limited to within 2% of average increase for the group leaders.
Annual bonus
Operation
Highlights
150% of salary on target, 225% maximum.
Metrics focused on safety and operational risk,
and on value creation.
Details on performance measures will be explained each
year in annual report on remuneration.
Executive directors are eligible for an annual bonus (before any deferral) of
150% of salary at target and 225% at maximum. Bonuses for the group
chief executive and the chief financial officer will be based entirely on
group measures. Executive directors with large operating responsibilities
may have up to 50% of their bonus based on their respective business
segment, with the balance based on group measures.
The strategy provides the overall context for the company’s key
performance indicators and the focus for the annual plan. From this,
measures and targets to reflect the key priorities of the business are
selected at the start of the year for senior managers, including executive
directors. Measures typically include a range of financial and operating
ones as well as those relating to safety and the environment.
Where possible, the committee uses quantifiable, hard targets that can be
factually measured and objectively assessed. Where it is appropriate to
use qualitative measures, the information used to make assessments will
be established at the start of or early in the year. Targets are set so that
achieving plan levels of performance results in on-target bonus. For
maximum levels, targets reflect performance levels that the committee
judges are very stretching but nonetheless achievable.
At the end of each year, performance is assessed relative to the measures
and targets established at the start of the year, adjusted for any material
changes in the market environment (predominantly oil prices).
In addition to the specific bonus metrics, the committee also reviews the
underlying performance of the group in light of the annual plan,
competitors’ results and analysts’ reports, and seeks input from other
committees on relevant aspects. When appropriate, the committee may
make adjustments, up or down, to a straight formulaic result based on this
fuller information. The committee considers that this informed judgement
is important to establishing a fair overall assessment.
The rigorous process followed by the committee has resulted in bonus
levels varying considerably over a number of years, reflecting the changing
circumstances of the company during the period. The following chart
shows the average annual bonus result (before any deferral) relative to an
on-target level for executive directors.
100
The committee will make a balanced judgement of what, if any, increase
should be applied to each executive director’s salary. These decisions, and
the reasons for them, form part of the annual report of remuneration.
Benefits and other emoluments
Executive directors are entitled to receive those benefits which are made
available to employees generally in accordance with their applicable terms,
for example sharesave plans, sickness policy, relocation assistance and
maternity pay. Benefits are not pensionable.
In addition, executive directors may receive other benefits that are judged to
be cost effective and prudent in terms of the individual’s time and/or
security. These include car-related benefits, security assistance, tax
preparation assistance, insurance and medical benefits. The costs of these
are treated as taxable benefits to the individuals and are included in the
single figure table of the annual report on remuneration. The company would
meet any tax charges arising in respect of benefits provided to directors that
it considers relate to its business (for example security assistance).
The committee expects to maintain benefits at their current level for the
duration of this policy but notes that the taxable value may fluctuate
depending on, amongst other things, insurance premiums, and a director’s
personal circumstances.
History of annual bonus results
On-target
200
Average actual result
t
e
g
r
a
t
f
o
%
150
100
50
2008
2009
2010
2011
2012
2013
Performance measures
The measures used to determine bonus results will derive from the annual
plan and support the strategic priorities of safety and operational risk
(S&OR) management and reinforcing value creation.
The committee determines specific measures, weightings and targets
each year to reflect the group’s strategy, key performance indicators (KPIs)
and the priorities in the annual plan. These measures will be reported each
year in the annual report on remuneration.
For safety and operational risk management the measures may include
established ones such as loss of primary containment, tier 1 process
safety events, recordable injury frequency, and/or days away from work
frequency. The measures selected will typically track both process and
personal safety and give an overall perspective on performance. The
committee will also seek the input of the safety, ethics and environmental
assurance committee (SEEAC) to determine if there are any other factors
or metrics that should be considered in arriving at a final assessment at
year end.
Value creation will form the principal measures and include both financial
and operating metrics that track performance relative to value creation.
Financial measures for value creation may include operating cash flow,
underlying replacement cost profit, and cost management or other similar
measures tracking the financial outcome of the company’s pursuit of
strategic goals. Additional operating metrics may include major project
delivery, Upstream unplanned deferrals, and Downstream net income per
barrel or other similar measures that track key operating aspects of the
strategy.
Where segment metrics are applied, they will typically include specific
safety metrics for the segment as well as value metrics such as availability,
efficiency, profitability and major project delivery.
BP Annual Report and Form 20-F 2013
Deferred bonus
The structure of deferred bonus, awarded in shares, focuses on long-term
alignment with shareholder interests and reinforces the critical importance
of maintaining high safety and environmental standards. It translates the
outcome of a portion of the annual bonus into a long-term plan with
additional performance hurdles. As shown below, the deferred bonus is
converted to shares, matched and deferred for three years. Half the total
that vests will then normally have an additional three-year retention
period before release.
Y
e
a
r
2
r 3
a
e
Y
Three-year
deferral
Y
e
a
r
5
r 6
a
e
Y
Three-year
retention
for half
Total deferred
bonus
Converted to shares
and matched
r 1
Y e a
Vests based on
performance
r 4
Y e a
Balance released
Half released
Performance measures
The safety and environmental sustainability hurdle, in place since 2010, will
continue to be applied to all deferred shares. If the committee assesses
that there has been a material deterioration in safety and environmental
metrics, or there have been major incidents either of which reveal
underlying weaknesses in safety and environmental management, then it
may conclude that shares vest in part, or not at all. In reaching its
conclusion, the committee will obtain advice from the SEEAC.
The committee believes that this safety and environmental hurdle is
appropriate for several reasons:
• High standards in this area are an important priority of BP’s strategy.
• Maintaining safety and environmental standards over the long term is a
good qualitative reflection of the sustainability of the business.
• This non-financial hurdle complements the financial and operational
performance conditions applicable to performance share awards.
Operation
Highlights
A third mandatory and up to a third voluntary deferral.
Converted to shares, matched one-for-one and deferred for three years.
Vesting of all conditional on safety and environmental sustainability hurdle.
Matched shares subject to additional three-year retention period post
vesting.
A third of the annual bonus is required to be deferred for three years. Under
the rules of the plan, the average share price over the three days following
the announcement of full-year results is used to determine the number of
shares awarded. Deferred shares are matched on a one-for-one basis.
Executive directors may elect, with the committee’s agreement, to take up
to a further third of their annual bonus in shares, which will vest and will
qualify for matching on the same basis as above.
Both deferred and matched shares vest after three years depending on the
committee’s assessment of safety and environmental sustainability over
the three-year deferral period. Where shares vest, the executive director
will also receive additional shares representing the value of the reinvested
dividends on those shares.
Beginning with the 2013 bonus deferral, matched shares that vest (half of
the total that vests) will normally be subject to a compulsory retention
period of a further three years. Sufficient shares may be sold to discharge
tax liabilities at the vesting date.
101
Corporate governanceBP Annual Report and Form 20-F 2013
Performance shares
The performance share element reflects the committee’s policy that a
large proportion of remuneration is tied to long-term performance. This
three-year performance period, combined with a further three-year
retention period for those shares that vest, creates a six-year incentive plan
designed to ensure executive interests are aligned with those of
shareholders.
Y
e
a
r
2
r 3
a
e
Y
Three-year
performance
period
Y
e
a
r
5
r 6
a
e
Y
Three-year
retention
period
Award
r 1
Y e a
Shares vest based
on performance
r 4
Y e a
Released
Operation
Highlights
Shares awarded to five and a half times salary for the group chief
executive and four times for other executive directors.
Three-year performance period.
Performance measures reflect strategy and KPIs.
Three-year retention period for those shares that vest.
Performance shares may be awarded conditionally at the start of each year
to a value of up to five and a half times salary for the group chief executive
and up to four times salary for the other executive directors (the maximum
allowed under the EDIP). Under the rules of the EDIP, the average share
price over the final quarter before the start of the performance period is
used to determine the number of shares awarded. Performance shares will
only vest to the extent that performance conditions are met.
Where shares vest, the executive director will receive additional shares
representing the value of the reinvested dividends on those shares.
Sufficient shares may be sold at vesting to discharge tax liabilities. The
remaining vested shares will normally be subject to a compulsory retention
period of a further three years.
A history of vesting of the share element is shown below, reflecting both
demanding performance conditions and poor company performance
during this period.
History of performance share vesting
2007-09
2008-10
2009-11
2010-12
2011-13
100
80
60
40
20
d
e
t
s
e
v
m
u
m
x
a
m
i
f
o
%
102
Performance measures
Performance measures will be aligned to BP’s strategy that focuses on
value creation and reinforcing safety and operational risk management.
Vesting of a portion of shares will be based on our total shareholder return
(TSR) compared to other oil majors, reflecting the central importance of
restoring and maintaining the value of the company. A further portion will
be based on the operating cash flow of the company, reflecting a central
element of value creation. The final portion will be based on a set of
strategic imperatives such as reserves replacement ratio, S&OR
management, and major project delivery.
For the TSR and the reserves replacement ratio measures, the comparator
group will continue to consist of ExxonMobil, Shell, Total and Chevron. This
group can be altered by the committee if circumstances change, for
example, if there is significant consolidation in the industry. While a narrow
group, it continues to represent the comparators that both shareholders
and management use in assessing relative performance.
TSR will be calculated by taking the share price performance over the
three-year performance period, assuming dividends are reinvested. All
share prices will be averaged over the three-month period before the
beginning and end of the performance period. They will be measured in
US dollars.
The methodology used for the relative measures will rank each of the five
oil majors on each measure. Performance shares for each component will
vest at levels of 100%, 80% and 25% respectively, for performance
equivalent to first, second and third place. No shares will vest for fourth
or fifth place.
Operating cash flow has been identified as a core measure of strategic
performance of the company. Targets will reflect agreed plans and normal
operating assumptions.
The committee will determine the weightings, specific measures and
targets for each year to reflect the strategic priorities for that year and the
committee’s judgement of where the focus should be for the upcoming
period. These will be explained in the annual report on remuneration.
The committee considers that a combination of quantitative and qualitative
measures reflects the long-term value creation priorities and the factors
underpinning business sustainability.
The committee may exercise its judgement, in a reasonable and informed
manner, to adjust vesting levels upwards or downwards if it concludes
that this approach does not reflect the reality of the health and
performance of the business relative to its peers. In addition the
committee will review whether the level of vesting is consistent with
shareholder interests. Any adjustments are explained in the annual report
on remuneration following vesting, in line with its commitment to
transparency.
BP Annual Report and Form 20-F 2013
Pension
Executive directors are eligible to participate in the pension schemes that
apply in their home country and which follow the national norms for
structure and levels.
UK executive directors
Highlights
US executive directors
Highlights
Defined benefit core schemes.
Annual accrual of 1.3% of average annual earnings generally provides
overall benefit.
Average earnings include salary and bonus.
Pension benefits in the US are provided through a combination of
tax-qualified and non-qualified benefit plans, consistent with applicable
US tax regulations.
The BP retirement accumulation plan (US pension plan) is a US
tax-qualified plan that features a cash balance formula and includes
grandfathering provisions under final average pay formulae for certain
employees of companies acquired by BP (including Amoco and Arco) who
participated in these predecessor company pension plans.
The TNK-BP supplemental retirement plan is a lump sum benefit based
on the same calculation as the benefit under the US pension plan but
reflecting service and earnings at TNK-BP.
The BP excess compensation (retirement) plan (excess compensation plan)
provides a supplemental benefit which is the difference between (a) the
benefit accrual under the US pension plan and the TNK-BP supplemental
retirement plan without regard to the IRS compensation limit (including for
this purpose base salary, cash bonus and bonus deferred into a
compulsory or voluntary award under the deferred matching element of
the EDIP), and (b) the actual benefit payable under the US pension plan and
the TNK-BP supplemental retirement plan, applying the IRS compensation
limit. The benefit calculation under the Amoco formula includes a reduction
of 5% per year if taken before age 60.
The BP supplemental executive retirement benefit plan (SERB) is a
supplemental plan based on a target of 1.3% of final average earnings
(including, for this purpose, base salary plus cash bonus and bonus
deferred into a compulsory or voluntary award under the deferred matching
element of the EDIP) for each year of service (without regard for tax limits)
less benefits paid under all other BP (US) qualified and non-qualified
pension arrangements. The benefit payable under SERB is unreduced at
age 60 but reduced by 5% per year if separation occurs before age 60.
Benefits payable under this plan are unfunded and therefore paid from
corporate assets.
Defined benefit core schemes.
One sixtieth annual accrual to a maximum
of two-thirds final salary.
35% cash supplement in lieu of future service
accrual for those in excess of UK government limits.
UK executive directors are members of the BP pension scheme in respect
of service prior to 1 April 2011. The core benefits under this scheme are
non-contributory. The benefits include a pension accrual of one sixtieth of
basic salary for each year of service, up to a maximum of two-thirds of final
basic salary and a dependant’s benefit of two-thirds of the member’s
pension. The scheme pension is not integrated with state pension
benefits. Higher accrual rules are offered to employees on the payment of
personal contributions.
Since 1 April 2011, participants may receive a cash supplement in lieu of
future service pension accrual in the BP pension scheme. This follows the
reduction in the annual allowance applicable to plans such as the BP
pension scheme in 2011. Some participants ceased pension accrual for
future service to remain within the new annual allowance. For these
employees the cash supplement is equal to 35% of basic salary.
Until the end of March 2011, pension benefits in excess of the individual
lifetime allowance set by legislation were paid via an unapproved,
unfunded pension arrangement provided directly by the company. From
April 2011 only increases in accrued benefits due to increases in salary in
excess of the individual lifetime allowance are covered by the
arrangements.
The rules of the BP pension scheme were amended in 2006 to reflect the
normal retirement age of 65. Prior to 1 December 2006, scheme members
could retire on or after age 60 without reduction.
Special early retirement terms apply to executives in service on
1 December 2006. If they retire between 60 and 65, they are entitled to an
immediate unreduced pension. If they retire between 55 and 60, they are
entitled to an immediate unreduced pension in respect of the proportion of
their benefit for service up to 30 November 2006, and are subject to such
reduction as the scheme actuary certifies in respect of the period of
service after 1 December 2006. For retirees leaving in circumstances
approved by the committee, the scheme actuary has to date applied a
reduction of 3% per annum in respect of the period of service from
1 December 2006 up to the leaving date; however a greater reduction can
be applied in other circumstances. Those leaving before 55 are entitled to
a deferred pension that becomes payable from 55 or later, on the basis set
out above. Irrespective of this, an individual leaving in circumstances of
total incapacity is entitled to an immediate unreduced pension as from their
leaving date.
103
Corporate governanceBP Annual Report and Form 20-F 2013 Scenario charts
The total remuneration opportunity for executive directors is strongly
performance based and weighted to the long term. The charts below
provide scenarios for the total remuneration of executive directors at
different levels of performance and are calculated as prescribed in UK
regulations. The fixed component in each chart includes current salary,
taxable benefits and pension. The annual component reflects cash bonus,
and in the case of Bob Dudley the pension accruing on his bonus. The long
term includes both the deferred bonus and the performance shares.
Detailed calculation assumptions are noted to the right of the charts.
58%
22%
20%
Target
$11,610
55%
19%
26%
Target
£3,844
55%
19%
26%
Target
£4,200
Calculation assumptions
76%
Minimum
Fixed components only
• Current salary and taxable benefits.
• Pension value of one year’s service using current salary for US and cash
in lieu for UK.
– UK 35% x salary.
– US 1.3% x salary x 20.
12%
12%
Maximum
$20,061
Target
Fixed
• Current salary and taxable benefits.
• Pension value of one year’s service using current salary for US and cash
in lieu for UK.
– UK 35% x salary.
– US 1.3% x salary x 20.
Annual
• Cash bonus reflecting on-target level of 150% of salary of which two
76%
thirds are paid in cash.
8%
16%
Maximum
£6,506
76%
8%
16%
Maximum
£7,102
• For Bob Dudley, pension value of one year’s service based on target
bonus times 20 (1.3% x 150% x salary x 20).
Long term
• Deferred bonus reflecting one third of target bonus of 150% of salary
and one-for-one match.
• Performance shares that vest to half maximum amounting to 2.75
times salary for Bob Dudley and two times salary for Iain Conn and
Dr Brian Gilvary.
Maximum
Fixed
• Current salary and taxable benefits.
• Pension value of one year’s service using current salary for US and cash
in lieu for UK.
– UK 35% x salary.
– US 1.3% x salary x 20.
Annual
• Cash bonus reflecting maximum of 225% of salary of which one third is
paid in cash.
• For Bob Dudley, pension value of one year’s service based on maximum
bonus times 20 (1.3% x 225% x salary x 20).
Long term
• Deferred bonus reflecting two thirds of maximum bonus of 225% of
salary and one-for-one match.
• Performance shares that fully vest amounting to five and a half times
salary for Bob Dudley and four times salary for Iain Conn and
Dr Brian Gilvary.
Bob Dudley ($ thousand)
Annual
Long term
Fixed
$20,000
$15,000
$10,000
$5,000
100%
Minimum
$2,358
Dr Brian Gilvary (£ thousand)
Fixed
Annual
Long term
£8,000
£6,000
£4,000
£2,000
100%
Minimum
£1,004
Iain Conn (£ thousand)
Fixed
Annual
Long term
100%
Minimum
£1,104
£8,000
£6,000
£4,000
£2,000
104
BP Annual Report and Form 20-F 2013 Recruitment
The committee expects any new executive directors to be engaged on
terms that are consistent with the policy as described on the preceding
pages. The committee recognizes that it cannot always predict accurately
the circumstances in which any new directors may be recruited. The
committee may determine that it is in the interests of the company and
shareholders to secure the services of a particular individual which may
require the committee to take account of the terms of that individual’s
existing employment and/or their personal circumstances. Accordingly, the
committee will ensure that:
• Salary level of any new director is competitive relative to the peer group.
• Variable remuneration will be awarded within the parameters outlined on
pages 98-99, save that the committee may provide that an initial award
under the EDIP (within the salary multiple limits on page 98) is subject to
a requirement of continued service over a specified period, rather than a
corporate performance condition.
• Where an existing employee of BP is promoted to the board, the
company will honour all existing contractual commitments including any
outstanding share awards or pension entitlements.
• Where an individual is relocating in order to take up the role, the
company may provide certain one-off benefits such as reasonable
relocation expenses, accommodation for a period following appointment
and assistance with visa applications or other immigration issues and
ongoing arrangements such as tax equalization, annual flights home, and
housing allowance.
• Where an individual would be forfeiting valuable remuneration in
order to join the company, the committee may award appropriate
compensation. The committee would require reasonable evidence of
the nature and value of any forfeited award and would,
to the extent practicable, ensure any compensation was no more
valuable than the forfeited award and that it was paid in the form of
shares in the company.
The committee would expect any new recruit to participate in the
company pension and benefit schemes that are open to senior employees
in his home country but would have due regard to the recruit’s existing
arrangements and market norms.
In making any decision on any aspect of the remuneration package for a
new recruit, the committee would balance shareholder expectations,
current best practice and the requirements of any new recruit and would
strive not to pay more than is necessary to achieve the recruitment. The
committee would give full details of the terms of the package of any new
recruit in the next remuneration report.
Service contracts
Summary details of each executive director’s service agreement are as
follows:
Bob Dudley
Iain Conn
Dr Brian Gilvary
Service
agreement date
6 Apr 2009
22 Jul 2004
22 Feb 2012
Salary as at
1 Jan 2014
$1,800,000
£774,000
£710,000
Bob Dudley’s contract is with BP Corporation North America Inc. He is
seconded to BP p.l.c. under a secondment agreement dated 15 April 2009,
which has been further extended to 15 April 2019. His secondment can be
terminated with one month’s notice by either party and terminates
automatically on the termination of his service agreement. Iain Conn’s and
Dr Brian Gilvary’s service agreements are with BP p.l.c.
Each executive director is entitled to pension provision, details of which are
summarized on page 103.
Each executive director is entitled to the following contractual benefits:
• A company car and chauffeur for business and private use, on terms that
the company bear all normal servicing, insurance and running costs.
Alternatively, the executive director is entitled to a car allowance in lieu.
• Medical and dental benefits, sick pay during periods of absence and tax
preparation assistance.
• Indemnification in accordance with applicable law.
• Each executive director participates in bonus or incentive arrangements
at the committee’s sole discretion. Currently, each participates in the
discretionary bonus scheme and the deferred bonus and performance
share plans as described on pages 100, 101 and 102 respectively.
Each executive director may terminate his employment by giving his
employer 12 months’ written notice. In this event, for business reasons,
the employer would not necessarily hold the executive director to his full
notice period.
Other than in the case of Dr Brian Gilvary (who became a director on
1 January 2012), the service agreements are expressed to expire at a
normal retirement age of 60; however, such executive directors could not,
under UK law, be required to retire at this (or any other) age following
abolition of the default retirement age.
The employer may lawfully terminate the executive director’s employment
in the following ways:
• By giving the director 12 months’ written notice.
• Without compensation, in circumstances where the employer is entitled
to terminate for cause, as defined for the purposes of his service
agreement.
Additionally, in the case of Iain Conn and Dr Brian Gilvary, the company
may lawfully terminate employment by making a lump sum payment in lieu
of notice equal to 12 months’ base salary. The company may elect to pay
this sum in monthly instalments rather than as a lump sum.
The lawful termination mechanisms described above are without prejudice
to the employer’s ability in appropriate circumstances to terminate in
breach of the notice period referred to above, and thereby to be liable for
damages to the executive director.
In the event of termination by the company, each executive director may
have an entitlement to compensation in respect of his statutory rights under
employment protection legislation in the UK and potentially elsewhere.
Where appropriate the company may also meet a director’s reasonable
legal expenses in connection with either his appointment or termination of
his appointment.
The committee considers that its policy on termination payments arising
from the contractual provisions summarized above provides an appropriate
degree of protection to the director in the event of termination and is
consistent with UK market practice.
Exit payments
Should it become necessary to terminate an executive director’s
employment, and therefore to determine a termination payment, the
committee’s policy would be as follows:
• The director’s primary entitlement would be to a termination payment in
respect of his service agreement, as set out above. The committee will
consider mitigation to reduce the termination payment to a leaving
director when appropriate to do so, taking into account the
circumstances and the law governing the agreement. Mitigation would
not be applicable where a contractual payment in lieu of notice is made.
In addition, the director may be entitled to a payment in respect of his
statutory rights. Other potential elements are as follows:
– First, the committee would consider whether the director should be
entitled to an annual bonus in respect of the financial year in which the
termination occurs. Normally, any such bonus would be restricted to
the director’s actual period of service in that financial year.
– Second, the committee would consider whether conditional share
awards held by the director under the EDIP should lapse on leaving or
should, at the committee’s discretion, be preserved (in which event
the award would normally continue until the normal vesting date and
be treated in the manner described on pages 101-102 of this report).
Any such determination will be made in accordance with the rules of
the EDIP, as approved by shareholders.
105
Corporate governanceBP Annual Report and Form 20-F 2013
– Third, if the departing director is eligible for an early retirement
pension, the committee would consider, if relevant under the terms of
the plan in which the director participates, the extent of any actuarial
reduction that should be applied.
• In determining the overall termination arrangements, the committee
would have regard to all relevant circumstances, and would therefore
distinguish between types of leaver and the circumstances under which
the director left the company. This mainly relates to consideration of
how discretion would be exercised in relation to conditional share
awards under the EDIP. It is also relevant where a departing director has
a right to an early retirement pension. UK directors who leave in
circumstances approved by the committee may have a favourable
actuarial reduction applied to their pensions (which has to date been
3%). Departing directors who leave in other circumstances are subject
to a greater reduction.
• The performance of the leaving director would be taken into account in
various respects. In particular, in deciding whether to exercise discretion
to preserve EDIP awards, the committee would have regard to the
director’s performance during the performance cycle of the relevant
awards, as well as a range of other relevant factors, including the
proximity of the award to its maturity date.
• The committee would also have regard to all other relevant factors,
including consideration of whether a contractual provision in the
director’s arrangements complied with best practice at the time the
director’s employment was terminated, as well as at the time the
provision was agreed to.
• A shorter vesting period for any share awards may apply on change of
control.
External appointments
The board supports executive directors taking up appointments outside the
company to broaden their knowledge and experience. Each executive
director is permitted to accept one non-executive appointment, from which
they may retain any fee. External appointments are subject to agreement
by the chairman and reported to the board. Any external appointment must
not conflict with a director’s duties and commitments to BP. Details of
appointments during 2013 are shown below.
Director
Bob Dudleya
Iain Conn
Appointee company
Rosneft
Rolls-Royce plc
Dr Byron Groteb
Unilever
Additional position held at
appointee company
Director
Senior independent
director and chairman of
the ethics committee
Audit committee
member
Total
fees
0
£82,000
Unilever PLC
£19,375
Unilever NV
e22,990
a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft.
b On retirement at 11 April 2013.
106
BP Annual Report and Form 20-F 2013 (b) Non-executive directors
This section of the directors’ remuneration report describes the separate
policies of the BP board for the remuneration of the chairman and the
non-executive directors (NEDs).
Key principles
The principles which underpin the board’s policies for the remuneration of
the chairman and the NEDs are as follows:
• Remuneration should be sufficient to attract, motivate and retain
world-class non-executive talent.
• Remuneration practice should be consistent with recognized best
practice standards for chairman and NED remuneration.
• The aggregate annual remuneration payable to the chairman and NEDs
is determined by shareholder resolution in accordance with the
company’s Articles of Association. The aggregate limit will be increased
Board remuneration policy for the chairman
The chairman is non-executive and, in accordance with the Governance
Code, independent on appointment. The quantum and structure of the
chairman’s remuneration is set by the board based upon a recommendation
from the remuneration committee. The chairman is not involved in setting
his own remuneration.
to £5 million if resolution 20 at the 2014 AGM is duly passed.
• NEDs should not receive share options, bonuses or retirement benefits
from the company.
• NEDs are encouraged to establish a holding in BP shares of the
equivalent value of one year’s base fee.
NEDs are supported through the company secretary’s office. This support
includes assistance with travel and transport, security advice (when
needed) and administrative services.
NEDs have letters of appointment that recognize that, subject to the
Articles of Association, their service is at the discretion of shareholders. All
directors stand for re-election at each AGM.
This policy reflects the approach adopted by the board over the years and
which has previously been described to shareholders.
Element and purpose
Operation and opportunity
Basic fee – chairman
Remuneration is in the form of cash fees, payable monthly.
Remuneration practice is consistent with recognized best
practice standards for a chairman’s remuneration and as a
UK-listed company, the quantum and structure of the
chairman’s remuneration will primarily be compared against
best UK practice.
Benefits and expenses
The chairman is provided with support and reasonable
travelling expenses.
The quantum and structure of chairman’s remuneration is reviewed
annually by the remuneration committee, which makes a
recommendation to the board.
The chairman is provided with an office and full time secretarial and
administrative support in London and a contribution to an office and
secretarial support in Sweden. A chauffeured car is provided in London,
together with security assistance. All reasonable travelling and other
expenses (including any relevant tax) incurred in carrying out his duties is
reimbursed.
The maximum remuneration for non-executive directors is set in accordance with the Articles of Association.
107
Corporate governanceBP Annual Report and Form 20-F 2013 Board remuneration policy for non-executive directors
Element
Operation
Basic fee
Remuneration is in the form of cash fees, payable monthly.
Remuneration practice is consistent with recognized best
practice standards for non-executive directors’ remuneration
and as a UK-listed company, the quantum and structure of
NED director remuneration will primarily be compared
against best UK practice.
The quantum and structure of NEDs’ remuneration is reviewed by the
chairman, the group chief executive and the company secretary who
make a recommendation to the board; the NEDs do not vote on their
own remuneration.
Remuneration for non-executive directors is reviewed annually.
Committee fees and allowances
Intercontinental allowance
The NEDs receive an allowance to reflect the global nature
of the Company’s business. The allowance is payable for
transatlantic or equivalent intercontinental travel for the
purpose of attending a board or committee meeting or site
visits.
Committee chairmanship fee
Those NEDs who chair a committee receive an additional
fee. The committee chairmanship fee reflects the additional
time and responsibility in chairing a committee of the board,
including the time spent in preparation and liaising with
management.
Committee membership fee
NEDs receive a fee for each committee on which they sit
other than as a chairman. The committee membership fee
reflects the time spent in attending and preparation for a
committee of the board.
The allowance will be paid in cash following each event of
intercontinental travel.
Fees for committee chairmanship and membership are
determined annually and paid in cash.
The senior independent director (SID)
In the light of the SID’s broader role and responsibilities, the
SID is paid a single fee and is entitled to other fees relating
to committees whether as chair or member.
The fee for the SID will be determined from time to time,
and is paid in cash monthly.
Benefits and expenses
The NEDs are provided with support and reasonable
travelling expenses.
Professional fees
Fees will be reimbursed in the form of cash, payable
following assistance.
NEDs are reimbursed for all reasonable travelling and subsistence
expenses (including any relevant tax) incurred in carrying out their duties.
The reimbursement of professional fees incurred by non-executive
directors based outside the UK in connection with advice and assistance
on UK tax compliance matters.
The maximum remuneration for non-executive directors is set in accordance with the Articles of Association.
This directors’ remuneration report was approved by the board and signed on its behalf by David J Jackson, company secretary on 6 March 2014.
108
BP Annual Report and Form 20-F 2013 Regulatory
information
110 Internal Control Revised Guidance for Directors (Turnbull)
110 Corporate governance practices
111 Code of ethics
111 Controls and procedures
111 Principal accountants’ fees and services
112 Memorandum and Articles of Association
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BP Annual Report and Form 20-F 2013
109
Internal Control Revised Guidance for Directors
(Turnbull)
In discharging its responsibility for the company’s risk management and
internal control systems under the UK Corporate Governance Code, the
board, through its governance principles, requires the group chief executive
to operate with a comprehensive system of controls and internal audit to
identify and manage the risks that are material to BP. The governance
principles are reviewed periodically by the board and are consistent with
the requirements of the UK Corporate Governance Code including principle
C.2 (risk management and internal control).
The board has an established process by which the effectiveness of the
system of internal control (which includes the risk management system) is
reviewed as required by provision C.2.1 of the UK Corporate Governance
Code. This process enables the board and its committees to consider the
system of internal control being operated for managing significant risks,
including strategic, safety and operational and compliance and control
risks, throughout the year. Material joint ventures and associates have not
been dealt with as part of the group in this process, although the board has
reviewed the exposure the group has to risk within joint arrangements.
As part of this process, the board and the audit, Gulf of Mexico and safety,
ethics and environment assurance committees requested, received and
reviewed reports from executive management, including management of
the business segments, corporate activities and functions, at their regular
meetings.
In considering the systems, the board noted that such systems are
designed to manage, rather than eliminate, the risk of failure to achieve
business objectives and can only provide reasonable, and not absolute,
assurance against material misstatement or loss.
During the year, the board through its committees regularly reviewed with
executive management processes whereby risks are identified, evaluated
and managed. These processes were in place for the year under review,
remain current at the date of this report and accord with the guidance on
the UK Corporate Governance Code provided by the Financial Reporting
Council. In December 2013, the board considered the group’s significant
risks within the context of the annual plan presented by the group chief
executive.
A joint meeting of the audit and safety, ethics and environment assurance
committees in January 2014 reviewed a report from the general auditor as
part of the board’s annual review of the risk management and internal
control systems. The report described the annual summary of internal
audit’s consideration of the design and operation of elements of BP’s
system of internal control over significant risks arising in the categories of
strategic and commercial, safety and operational and compliance and
control and considered the control environment for the group. The report
also highlighted the results of audit work conducted during the year and
the remedial actions taken by management in response to significant
failings and weaknesses identified.
During the year, these committees engaged with management, the
general auditor and other monitoring and assurance providers (such as the
group ethics and compliance officer, head of safety and operational risk
and the external auditor) on a regular basis to monitor the management of
risks. Significant incidents that occurred and management’s response to
them were considered by the appropriate committee and reported to the
board.
In the board’s view, the information it received was sufficient to enable it
to review the effectiveness of the company’s system of internal control in
accordance with the Internal Control Revised Guidance for Directors
(Turnbull).
Subject to determining any additional appropriate actions arising from
items still in process, the board is satisfied that, where significant failings
or weaknesses in internal controls were identified during the year,
appropriate remedial actions were taken or are being taken.
Corporate governance practices
In the US, BP ADSs are listed on the New York Stock Exchange (NYSE).
The significant differences between BP’s corporate governance practices
as a UK company and those required by NYSE listing standards for US
companies are listed as follows:
Independence
BP has adopted a robust set of board governance principles, which reflect
the UK Corporate Governance Code and its principles-based approach to
corporate governance. As such, the way in which BP makes
determinations of directors’ independence differs from the NYSE rules.
BP’s board governance principles require that all non-executive directors
be determined by the board to be ‘independent in character and judgement
and free from any business or other relationship which could materially
interfere with the exercise of their judgement’. The BP board has
determined that, in its judgement, all of the non-executive directors are
independent. In doing so, however, the board did not explicitly take into
consideration the independence requirements outlined in the NYSE’s
listing standards.
Committees
BP has a number of board committees that are broadly comparable in
purpose and composition to those required by NYSE rules for domestic US
companies. For instance, BP has a chairman’s (rather than executive)
committee, nomination (rather than nominating/corporate governance)
committee and remuneration (rather than compensation) committee. BP
also has an audit committee, which NYSE rules require for both US
companies and foreign private issuers. These committees are composed
solely of non-executive directors whom the board has determined to be
independent, in the manner described above.
The BP board governance principles prescribe the composition, main tasks
and requirements of each of the committees (see the board committee
reports on page 74). BP has not, therefore, adopted separate charters for
each committee.
Under US securities law and the listing standards of the NYSE, BP is
required to have an audit committee that satisfies the requirements of Rule
10A-3 under the Exchange Act and Section 303A.06 of the NYSE Listed
Company Manual. BP’s audit committee complies with these
requirements. The BP audit committee does not have direct responsibility
for the appointment, re-appointment or removal of the independent
auditors – instead, it follows the UK Companies Act 2006 by making
recommendations to the board on these matters for it to put forward for
shareholder approval at the AGM.
One of the NYSE’s additional requirements for the audit committee states
that at least one member of the audit committee is to have ‘accounting or
related financial management expertise’. The board determined that
Brendan Nelson possessed such expertise and also possesses the
financial and audit committee experiences set forth in both the UK
Corporate Governance Code and SEC rules (see Audit committee report
on page 74). Mr Nelson is the audit committee financial expert as defined
in Item 16A of Form 20-F.
110
BP Annual Report and Form 20-F 2013 Shareholder approval of equity compensation plans
The NYSE rules for US companies require that shareholders must be given
the opportunity to vote on all equity-compensation plans and material
revisions to those plans. BP complies with UK requirements that are similar
to the NYSE rules. The board, however, does not explicitly take into
consideration the NYSE’s detailed definition of what are considered
‘material revisions’.
The company’s management, with the participation of the company’s
group chief executive and chief financial officer, has evaluated the
effectiveness of the company’s disclosure controls and procedures
pursuant to Exchange Act Rule 13a-15(b) as of the end of the period
covered by this annual report. Based on that evaluation, the group chief
executive and chief financial officer have concluded that the company’s
disclosure controls and procedures were effective at a reasonable
assurance level.
Code of ethics
The NYSE rules require that US companies adopt and disclose a code of
business conduct and ethics for directors, officers and employees. BP has
adopted a code of conduct, which applies to all employees, and has board
governance principles that address the conduct of directors. In addition BP
has adopted a code of ethics for senior financial officers as required by the
SEC. BP considers that these codes and policies address the matters
specified in the NYSE rules for US companies.
Code of ethics
The company has adopted a code of ethics for its group chief executive,
chief financial officer, group controller, general auditor and chief accounting
officer as required by the provisions of Section 406 of the Sarbanes-Oxley
Act of 2002 and the rules issued by the SEC. There have been no waivers
from the code of ethics relating to any officers.
BP also has a code of conduct, which is applicable to all employees.
This was updated (and published) on 1 January 2012.
Controls and procedures
Evaluation of disclosure controls and procedures
The company maintains ‘disclosure controls and procedures’, as such term
is defined in Exchange Act Rule 13a-15(e), that are designed to ensure that
information required to be disclosed in reports the company files or
submits under the Exchange Act is recorded, processed, summarized and
reported within the time periods specified in the Securities and Exchange
Commission rules and forms, and that such information is accumulated
and communicated to management, including the company’s group chief
executive and chief financial officer, as appropriate, to allow timely
decisions regarding required disclosure.
In designing and evaluating our disclosure controls and procedures, our
management, including the group chief executive and chief financial
officer, recognize that any controls and procedures, no matter how well
designed and operated, can provide only reasonable, not absolute,
assurance that the objectives of the disclosure controls and procedures are
met. Because of the inherent limitations in all control systems, no
evaluation of controls can provide absolute assurance that all control issues
and instances of fraud, if any, within the company have been detected.
Further, in the design and evaluation of our disclosure controls and
procedures our management necessarily was required to apply its
judgement in evaluating the cost-benefit relationship of possible controls
and procedures. Also, we have investments in certain unconsolidated
entities. As we do not control these entities, our disclosure controls and
procedures with respect to such entities are necessarily substantially more
limited than those we maintain with respect to our consolidated
subsidiaries. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be
detected. The company’s disclosure controls and procedures have been
designed to meet, and management believes that they meet, reasonable
assurance standards.
Management’s report on internal control over financial
reporting
Management of BP is responsible for establishing and maintaining
adequate internal control over financial reporting. BP’s internal control over
financial reporting is a process designed under the supervision of the
principal executive and financial officers to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of BP’s
financial statements for external reporting purposes in accordance with
IFRS.
As of the end of the 2013 fiscal year, management conducted an
assessment of the effectiveness of internal control over financial reporting
in accordance with the Internal Control Revised Guidance for Directors
(Turnbull). Based on this assessment, management has determined that
BP’s internal control over financial reporting as of 31 December 2013 was
effective.
The company’s internal control over financial reporting includes policies
and procedures that pertain to the maintenance of records that, in
reasonable detail, accurately and fairly reflect transactions and dispositions
of assets; provide reasonable assurances that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
IFRS and that receipts and expenditures are being made only in accordance
with authorizations of management and the directors of BP; and provide
reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use or disposition of BP’s assets that could have
a material effect on our financial statements. BP’s internal control over
financial reporting as of 31 December 2013 has been audited by Ernst &
Young, an independent registered public accounting firm, as stated in their
report appearing on page 121 of BP Annual Report and Form 20-F 2013.
Changes in internal control over financial reporting
There were no changes in the group’s internal controls over financial
reporting that occurred during the period covered by the Form 20-F that
have materially affected or are reasonably likely to materially affect our
internal controls over financial reporting.
Principal accountants’ fees and services
The audit committee has established policies and procedures for the
engagement of the independent registered public accounting firm,
Ernst & Young LLP, to render audit and certain assurance and tax services.
The policies provide for pre-approval by the audit committee of specifically
defined audit, audit-related, tax and other services that are not prohibited
by regulatory or other professional requirements. Ernst & Young are
engaged for these services when its expertise and experience of BP are
important. Most of this work is of an audit nature. 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.
111
Corporate governanceBP Annual Report and Form 20-F 2013 Under the policy, pre-approval is given for specific services within the
following categories: advice on accounting, auditing and financial reporting
matters; internal accounting and risk management control reviews
(excluding any services relating to information systems design and
implementation); non-statutory audit; project assurance and advice on
business and accounting process improvement (excluding any services
relating to information systems design and implementation relating to BP’s
financial statements or accounting records); due diligence in connection
with acquisitions, disposals and joint arrangements (excluding valuation or
involvement in prospective financial information); income tax and indirect
tax compliance and advisory services; employee tax services (excluding
tax services that could impair independence); provision of, or access to,
Ernst & Young publications, workshops, seminars and other training
materials; provision of reports from data gathered on non-financial policies
and information; and assistance with understanding non-financial
regulatory requirements. BP operates a two-tier system for audit and
non-audit services. For audit related services, the audit committee has a
pre-approved aggregate level, within which specific work may be approved
by management. Non-audit services, including tax services, are pre-
approved for management to authorize per individual engagement, but
above a defined level must be approved by the chairman of the audit
committee or the full committee. The audit committee has delegated to
the chairman of the audit committee authority to approve permitted
services provided that the chairman reports any decisions to the
committee at its next scheduled meeting. Any proposed service not
included in the approved service list must be approved in advance by the
audit committee chairman and reported to the committee, or approved by
the full audit committee in advance of commencement of the
engagement.
The audit committee evaluates the performance of the auditors each year.
The audit fees payable to Ernst & Young are reviewed by the committee in
the context of other global companies for cost effectiveness. The
committee keeps under review the scope and results of audit work and the
independence and objectivity of the auditors. External regulation and BP
policy requires the auditors to rotate their lead audit partner every five
years. (See Financial statements – Note 37 and Audit committee report on
page 76 for details of audit fees.)
Memorandum and Articles of Association
The following summarizes certain provisions of the company’s
Memorandum and Articles of Association and applicable English law. This
summary is qualified in its entirety by reference to the UK Companies Act
2006 (Act) and the company’s Memorandum and Articles of Association.
For information on where investors can obtain copies of the Memorandum
and Articles of Association see Documents on display on page 279.
At the AGM held on 17 April 2008 shareholders voted to adopt new
Articles of Association, largely to take account of changes in UK company
law brought about by the Act. Further amendments to the Articles of
Association were approved by shareholders at the AGM held on 15 April
2010. There have been no further amendments to the Articles of
Association.
The Articles of Association may be amended by a special resolution.
Objects and purposes
BP is incorporated under the name BP p.l.c. and is registered in England
and Wales with the registered number 102498. The provisions regulating
the operations of the company, known as its ‘objects’, were historically
stated in a company’s memorandum. The Act abolished the need to have
object provisions and so at the AGM held on 15 April 2010 shareholders
approved the removal of its objects clause together with all other
provisions of its Memorandum that, by virtue of the Act, are treated as
forming part of the company’s Articles of Association.
Directors
The business and affairs of BP shall be managed by the directors. The
company’s Articles of Association provide that directors may be appointed
by the existing directors or by the shareholders in a general meeting. Any
person appointed by the directors will hold office only until the next general
meeting and will then be eligible for re-election by the shareholders.
A director may be removed by BP as provided for by applicable law and
shall vacate office in certain circumstances as set out in the Articles of
Association. There is no requirement for a director to retire on reaching
any age.
The Articles of Association place a general prohibition on a director voting
in respect of any contract or arrangement in which the director has a
material interest other than by virtue of such director’s 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
or any of its subsidiaries.
• Any proposal in which the director is interested, concerning the
underwriting of company securities or debentures or the giving of any
security to a third party for a debt or obligation of the company or any of
its subsidiaries.
• Any proposal concerning any other company in which the director is
interested, directly or indirectly (whether as an officer or shareholder or
otherwise) provided that the director and persons connected with such
director are not the holder or holders of 1% or more of the voting interest
in the shares of such company.
• Any proposal concerning the purchase or maintenance of any insurance
policy under which the director may benefit.
The 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
the director’s interest at a meeting of the directors of the company. The
definition of ‘interest’ includes the interests of spouses, children,
companies and trusts. The Act also requires that a director must avoid a
situation where a director has, or could have, a direct or indirect interest
that conflicts, or possibly may conflict, with the company’s interests. The
Act allows directors of public companies to authorize such conflicts where
appropriate, if a company’s Articles of Association so permit. BP’s Articles
of Association permit the authorization of such conflicts. 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 affected by amending the Articles of Association.
112
BP Annual Report and Form 20-F 2013 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. 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 IFRS and the Act. Dividends on ordinary shares are
payable only after payment of dividends on BP preference shares. Any
dividend unclaimed after a period of 12 years from the date of declaration
of such dividend shall be forfeited and reverts to BP.
The directors have the power to declare and pay dividends in any currency
provided that a sterling equivalent is announced. It is not the company’s
intention to change its current policy of paying dividends in US dollars. At
the company’s AGM held on 15 April 2010, shareholders approved the
introduction of a Scrip Dividend Programme (Programme) and to include
provisions in the Articles of Association to enable the company to operate
the Programme. The Programme enables ordinary shareholders and BP
ADS holders to elect to receive new fully paid ordinary shares (or BP ADSs
in the case of BP ADS holders) instead of cash. The operation of the
Programme is always subject to the directors’ decision to make the scrip
offer available in respect of any particular dividend. Should the directors
decide not to offer the scrip in respect of any particular dividend, cash will
automatically be paid instead.
Apart from shareholders’ rights to share in BP’s profits by dividend (if any is
declared or announced), 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.
• 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 the company 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 £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 are also entitled to attend, speak and vote at
any shareholders’ meeting of BP by the appointment by the approved
depositary, JPMorgan Chase Bank N.A., 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 BP 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 two types: ordinary or special.
An annual general meeting must be held once in every year.
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. A
special resolution requires the affirmative vote of not less than three-
fourths of the persons voting at a meeting at which there is a quorum. Any
AGM requires 21 days’ notice. The notice period for a general meeting is
14 days subject to the company obtaining annual shareholder approval,
failing which, a 21-day notice period will apply.
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 LSE during the
previous six months. The remaining assets (if any) would be divided pro
rata among the holders of ordinary shares.
Without prejudice to any special rights previously conferred on the holders
of any class of shares, BP may issue any share with such preferred,
deferred or other special rights, or subject to such restrictions as the
shareholders by resolution determine (or, in the absence of any such
resolutions, by determination of the directors), and may issue shares that
are to be or may be redeemed.
113
Corporate governanceBP Annual Report and Form 20-F 2013 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 on the adoption
of a special resolution passed at a separate meeting of the holders of the
shares of that class. At every such separate meeting, all of the provisions
of the Articles of Association relating to proceedings at a general meeting
apply, except that the quorum with respect to a meeting to change the
rights attached to the preference shares is 10% or more of the shares of
that class, and the quorum to change the rights attached to the ordinary
shares is one-third or more of the shares of that class.
Shareholders’ meetings and notices
Shareholders must provide BP with a postal or electronic address in the UK
to be entitled to receive notice of shareholders’ meetings. 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 are
described on page 113 under the heading Voting rights.
Under the Act, the AGM of shareholders must be held within the
six-month period once every year. All general meetings shall be held at a
time and place determined by the directors within the UK. 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. Powers exist for action to be taken either before or at the
meeting by authorized officers to ensure its orderly conduct and safety of
those attending.
Limitations on voting and shareholding
There are no limitations imposed by English law or the company’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 BP ADSs,
other than limitations that would generally apply to all of the shareholders
and limitations applicable to certain countries and persons subject to EU
economic sanctions.
Disclosure of interests in shares
The Act permits a public company to give notice to any person whom the
company believes to be or, at any time during the three years prior to the
issue of the notice, to have been interested in its voting shares requiring
them 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.
114
BP Annual Report and Form 20-F 2013 Financial
statements
116 Statement of directors’ responsibilities
117 Consolidated financial statements of the BP group
Independent auditor’s reports
Group income statement
Group statement of
comprehensive income
117
122
123
Group statement of changes in
equity
Group balance sheet
Group cash flow statement
123
124
125
126 Notes on financial statements
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
145
145
139
145
Significant accounting
policies, judgements,
estimates and assumptions 126
Significant event – Gulf of
Mexico oil spill
Business combinations
Non-current assets held for
sale
Disposals and impairment
Disposal of TNK-BP and
investment in Rosneft
148
Segmental analysis
149
Income statement analysis 154
Operating leases
154
Exploration for and
evaluation of oil and natural
gas resources
Taxation
155
156
158
Earnings per ordinary share 158
Property, plant and
equipment
160
11.
12. Dividends
13.
14.
16.
17.
15. Goodwill and impairment
review of goodwill
Intangible assets
Investments in joint
ventures
Investments in associates
Financial instruments and
financial risk factors
18.
19.
20. Other investments
161
163
163
164
166
170
21.
Inventories
170
Trade and other receivables 171
22.
23. Cash and cash equivalents 171
24. Valuation and qualifying
accounts
Trade and other payables
25.
26. Derivative financial
instruments
Finance debt
27.
28. Capital disclosures and
29.
30.
analysis of changes in net
debt
Provisions
Pensions and other post-
retirement benefits
31. Called-up share capital
32. Capital and reserves
Employee costs and
33.
numbers
34. Remuneration of directors
and senior management
35. Contingent liabilities
36. Capital commitments
37. Auditor’s remuneration
38. Subsidiaries, joint
arrangements and
associates
39. Condensed consolidated
information on certain US
subsidiaries
200 Supplementary information on oil and natural gas
(unaudited)
Oil and natural gas exploration
and production activities
Movements in estimated net
proved reserves
201
207
Standardized measure of
discounted future net cash flows
and changes therein relating to
proved oil and gas reserves
Operational and statistical
information
224 Parent company financial statements of BP p.l.c.
224
225
226
Independent auditor’s report to
the members of BP p.l.c.
Company balance sheet
Company cash flow statement
Company statement of total
recognized gains and losses
226
Notes on financial statements
227
Accounting policies
1.
227
Taxation
2.
228
Fixed assets – investments 228
3.
Debtors
Creditors
Pensions
Called-up share capital
Capital and reserves
Cash flow
4.
5.
6.
7.
8.
9.
10. Contingent liabilities
11. Share-based payments
12. Auditor’s remuneration
13. Directors’ remuneration
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
171
171
172
176
177
178
178
185
186
189
190
191
191
192
193
194
219
222
229
229
230
232
233
233
234
234
234
234
BP Annual Report and Form 20-F 2013
115
Statement of directors’ responsibilities
The directors are responsible for preparing the Annual Report and the financial statements in accordance with applicable law and regulations.
The directors are required by the UK Companies Act 2006 to prepare financial statements for each financial year that give a true and fair view of the
financial position of the group and the parent company and the financial performance and cash flows of the group and parent company for that period.
Under that law they are required to prepare the consolidated financial statements in accordance with International Financial Reporting Standards (IFRS)
as adopted by the European Union (EU) and applicable law and have elected to prepare the parent company financial statements in accordance with
applicable United Kingdom law and United Kingdom accounting standards (United Kingdom generally accepted accounting practice). In preparing the
consolidated financial statements the directors have also elected to comply with IFRSs as issued by the International Accounting Standards Board
(IASB). In preparing those financial statements, the directors are required to:
• select suitable accounting policies and then apply them consistently.
• make judgements and estimates that are reasonable and prudent.
• present information, including accounting policies, in a manner that provides relevant, reliable, comparable and understandable information.
• provide additional disclosure when compliance with the specific requirements of IFRS is insufficient to enable users to understand the impact of
particular transactions, other events and conditions on the group’s financial position and financial performance.
• state that applicable accounting standards have been followed, subject to any material departures disclosed and explained in the parent company
financial statements.
• prepare the financial statements on the going concern basis unless it is inappropriate to presume that the company will continue in business.
The directors are responsible for keeping proper accounting records that disclose with reasonable accuracy at any time the financial position of the
group and company and enable them to ensure that the consolidated financial statements comply with the Companies Act 2006 and Article 4 of the
IAS Regulation and the parent company financial statements comply with the Companies Act 2006. They are also responsible for safeguarding the
assets of the group and company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.
The directors draw attention to Note 2 on the consolidated financial statements which describes the uncertainties surrounding the amounts and
timings of liabilities arising from the Gulf of Mexico oil spill.
The group’s business activities, performance, position and risks are set out in this report. The financial position of the group, its cash flows, liquidity
position and borrowing facilities are detailed in the appropriate sections on pages 56 to 58 and elsewhere in the notes on the consolidated financial
statements. The report also includes details of the group’s risk mitigation and management. Information on the Gulf of Mexico oil spill and BP’s
response is included on pages 38 to 40 and elsewhere in this report, including Safety on pages 41 to 44. The group has considerable financial
resources, and the directors believe that the group is well placed to manage its business risks successfully. After making enquiries, the directors have
a reasonable expectation that the company and the group have adequate resources to continue in operational existence for the foreseeable future.
Accordingly, they continue to adopt the going concern basis in preparing the annual report and accounts.
Having made the requisite enquiries, so far as the directors are aware, there is no relevant audit information (as defined by Section 418(3) of the
Companies Act 2006) of which the company’s auditors are unaware, and the directors have taken all the steps they ought to have taken to make
themselves aware of any relevant audit information and to establish that the company’s auditors are aware of that information.
The directors confirm that to the best of their knowledge:
• the consolidated financial statements, prepared in accordance with IFRS as issued by the IASB, IFRS as adopted by the EU and in accordance with
the provisions of the Companies Act 2006, give a true and fair view of the assets, liabilities, financial position and profit or loss of the group;
• the parent company financial statements, prepared in accordance with United Kingdom generally accepted accounting practice, give a true and fair
view of the assets, liabilities, financial position, performance and cash flows of the company; and
• the management report, which is incorporated in the strategic report and directors’ report, includes a fair review of the development and
performance of the business and the position of the group, together with a description of the principal risks and uncertainties that they face.
Fair, balanced and understandable
In accordance with the principles of the UK Corporate Governance Code, the board has established arrangements to evaluate whether the information
presented in the Annual Report is fair, balanced and understandable: these are described on page 69.
The board considers the Annual Report and financial statements, taken as a whole, is fair, balanced and understandable and provides the information
necessary for shareholders to assess the company’s performance, business model and strategy.
C-H Svanberg Chairman
6 March 2014
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
116
BP Annual Report and Form 20-F 2013
Consolidated financial statements of the BP group
Independent auditor’s report on the Annual Report and Accounts to the members of BP p.l.c.
Opinion on the financial statements
In our opinion the consolidated financial statements:
• give a true and fair view of the state of the group’s affairs as at 31 December 2013 and of its profit for the year then ended;
• have been properly prepared in accordance with IFRS as adopted by the European Union; and
• have been prepared in accordance with the requirements of the Companies Act 2006 and Article 4 of the IAS Regulation.
Emphasis of matter – significant uncertainty over provisions and contingencies related to the Gulf of Mexico oil spill
In forming our opinion we have considered the adequacy of the disclosures made in Note 2 to the financial statements concerning the provisions,
future expenditures for which reliable estimates cannot be made and other contingencies related to the Gulf of Mexico oil spill significant event. The
total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the ultimate
exposure and cost to BP will be dependent on many factors. Furthermore, significant uncertainty exists in relation to the amount of claims that will
become payable by BP, the amount of fines that will ultimately be levied on BP (including any determination of BP’s culpability based on any findings of
negligence, gross negligence or wilful misconduct), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term
environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP. Our opinion is not qualified in respect of these
matters.
Separate opinion in relation to IFRS as issued by the International Accounting Standards Board
As explained in Note 1 to the consolidated financial statements, the group in addition to applying IFRS as adopted by the European Union, has also
applied IFRS as issued by the International Accounting Standards Board (IASB). In our opinion the consolidated financial statements comply with IFRS
as issued by the IASB.
What we have audited
The consolidated financial statements of BP p.l.c for the year ended 31 December 2013 comprise the group income statement, the group statement of
comprehensive income, the group statement of changes in equity, the group balance sheet, the group cash flow statement and the related notes 1 to
38. The financial reporting framework that has been applied in their preparation is applicable law and International Financial Reporting Standards (IFRS)
as adopted by the European Union.
This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work
has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for
no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the
company’s members as a body, for our audit work, for this report, or for the opinions we have formed.
Respective responsibilities of directors and auditor
As explained more fully in the Statement of directors’ responsibilities set out on page 116, the directors are responsible for the preparation of the
consolidated financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on the
consolidated financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards require
us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.
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Scope of the audit of the financial statements
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the
financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting
policies are appropriate to the group’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant
accounting estimates made by the directors; and the overall presentation of the financial statements. In addition, we read all the financial and non-
financial information in the Annual Report and Accounts to identify material inconsistencies with the audited financial statements and to identify any
information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of performing
the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.
Our assessment of risks of material misstatement
We identified the following risks that have the greatest effect on the overall audit strategy; the allocation of audit resource; and in directing the efforts
of the audit engagement team:
• the significant uncertainties over provisions and contingencies related to the Gulf of Mexico oil spill;
• the impact of the estimation of the quantity of oil and gas reserves on impairment testing, depreciation, depletion and amortization and
decommissioning provisions;
• unauthorized trading activity;
• BP’s ability to exercise significant influence over Rosneft and the consequent accounting for the interest in Rosneft using the equity method; and
• the fair value accounting on the acquisition of the equity interest in Rosneft.
Our application of materiality
We apply the concept of materiality in planning and performing our audit, and in evaluating the effect of misstatements on our audit and on the financial
statements. For the purposes of determining whether the financial statements are free from material error, we define materiality as the magnitude of
an omission or misstatement that, individually or in the aggregate, in light of the surrounding circumstances, could reasonably be expected to influence
the economic decisions of the users of the financial statements.
When establishing our overall audit strategy, we determined the magnitude of uncorrected and undetected misstatements that we judged would be
material for the financial statements as a whole. We determined materiality for the group to be $1 billion (2012 $1 billion). Our evaluation of materiality
requires professional judgement and necessarily takes into account qualitative as well as quantitative (i.e. profit before taxation in the group income
statement) considerations implicit in the definition. This materiality provided a basis for identifying and assessing the risk of material misstatement and
determining the nature, timing and extent of further audit procedures.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2013
117
Consolidated financial statements of the BP group
Independent auditor’s report on the Annual Report and Accounts to the members of
BP p.l.c. – continued
On the basis of our risk assessments, together with our assessment of the group’s overall control environment, our judgement was that overall
performance materiality (that is our tolerance for misstatement in an individual account or balance) for the group should be 75% (2012 75%) of the
materiality we have determined for the group, namely $750 million (2012 $750 million). Our objective in adopting this approach was to ensure that total
uncorrected and undetected audit differences do not exceed our materiality level of $1 billion for the financial statements as a whole.
We agreed with the audit committee that we would report to the committee all audit differences in excess of $50 million (2012 $50 million), as well as
differences below that threshold that, in our view, warranted reporting on qualitative grounds.
An overview of the scope of our audit
We adopted a risk-based approach in determining our audit strategy. This approach focuses audit effort towards higher risk areas, such as
management judgements and estimates and on locations that are considered significant based upon size, complexity and risk.
Our group audit scope focused on key locations. They were selected to provide an appropriate basis for undertaking audit work to address the risks of
material misstatement identified above. Together with the group functions, which are also subject to audit, these locations represent the principal
business units of the group and account for 75% (2012 72%) of the group’s total assets and 84% (2012 72%) of the group’s profit before tax. All
locations within the scope were subject to audit procedures and the extent of audit work was based on our assessment of the risks of material
misstatement and of the materiality of the group’s business operations at those locations. For the remaining locations, we performed other procedures
to ensure there were no significant risks of material misstatement in the group financial statements.
One of the key locations in scope for the group audit is Rosneft, a material associate that represents approximately 4% of the group’s total assets and
7% of the group’s profit before tax. Rosneft is not controlled by the group. We were provided with sufficient access to Rosneft’s auditors in order to
ensure appropriate audit procedures had been completed by them on the financial statements of Rosneft from which the BP equity accounting entries
are determined.
The group audit team continued to follow a programme of planned visits that were designed to ensure that the Senior Statutory Auditor or his
designates visit each of the locations where the group audit scope was focused at least once every two years and the most significant of them at least
once a year. The Senior Statutory Auditor visited Houston four times during the audit primarily to consider the uncertainties over provisions and
contingencies related to the Gulf of Mexico oil spill and he visited Moscow three times primarily to consider the matters related to the equity interest in
Rosneft.
Our response to the risks of material misstatement identified above included the following procedures:
• we focused on the significant uncertainties over provisions and contingencies related to the Gulf of Mexico oil spill; specifically the areas of highest
uncertainty where assumptions or new events could result in a material change to the provisions recorded or contingent liabilities disclosed. We
engaged actuaries to work with the audit team and challenge the expert input provided to BP by external actuaries. We considered the legal opinions
that determined management’s positions, in particular relating to whether BP will be found grossly negligent and the implications for the fines and
penalties payable under the Clean Water Act.
• we performed testing of controls over BP’s internal certification process for technical and commercial experts who are responsible for the estimation
of oil and gas reserves. We assessed whether the changes in proved reserves have been made in compliance with relevant regulations. We ensured
that the updated reserves estimates were included appropriately in consideration of impairment, depreciation, depletion and amortization and
decommissioning provisions.
• we performed testing relating to controls over unauthorized trading activity and obtained confirmations directly from third parties for a sample of
trades. Analytical tools were used to assist us in identifying trades which have the highest risk of unauthorized activity so as to focus our testing on
these trades.
• we challenged management’s judgement that BP exercises significant influence over Rosneft, including obtaining evidence of BP’s participation in
decision-making through representation on the Rosneft board and committees of the board.
• we challenged management’s assumptions used in the determination of the fair value of the assets and liabilities of the Rosneft business. We
engaged valuations specialists to work with the audit team to consider the valuation methodology and specifically the assumptions used around
future oil and gas prices, exchange rates and discount rates. We performed procedures to ensure the veracity of the valuation model and that the
base data used in the model agreed to the underlying books and records.
Opinion on other matter prescribed by the Companies Act 2006
In our opinion the information given in the Strategic Report and the Directors’ Report for the financial year for which the consolidated financial
statements are prepared is consistent with the consolidated financial statements.
Matters on which we are required to report by exception
We have nothing to report in respect of the matters set out below.
Under the International Standards on Auditing (UK and Ireland), we are required to report to you if, in our opinion, information in the annual report is:
• materially inconsistent with the information in the audited financial statements; or
• apparently materially incorrect based on, or materially inconsistent with, our knowledge of the group acquired in the course of performing our audit;
or
• is otherwise misleading.
In particular, we are required to consider whether we have identified any inconsistencies between our knowledge acquired during the audit and the
directors’ statement that they consider the annual report is fair, balanced and understandable and whether the annual report appropriately discloses
those matters that we communicated to the audit committee which we consider should have been disclosed.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
118
BP Annual Report and Form 20-F 2013
Consolidated financial statements of the BP group
Independent auditor’s report on the Annual Report and Accounts to the members of
BP p.l.c. – continued
Under the Companies Act 2006 we are required to report to you if, in our opinion:
• certain disclosures of directors’ remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
Under the Listing Rules we are required to review:
• the statement of directors’ responsibilities, set out on page 116, in relation to going concern; and
• the part of the Governance and Risk section of the Annual Report relating to the company’s compliance with the nine provisions of the UK Corporate
Governance Code specified for our review.
Other matter
We have reported separately on the parent company financial statements of BP p.l.c. for the year ended 31 December 2013 and on the information in
the Directors’ remuneration report that is described as having been audited.
Ernst & Young LLP
John C. Flaherty (Senior Statutory Auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
6 March 2014
1. The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not
involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the
financial statements since they were initially presented on the website.
2. Legislation in the United Kindom governing the preparation and dissemination of financial statements may differ from legislation in other
jurisdictions.
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This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2013
119
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm on the Annual Report on Form 20-F
The Board of Directors and Shareholders of BP p.l.c.
We have audited the accompanying group balance sheets of BP p.l.c. as of 31 December 2013, 31 December 2012 and 1 January 2012, and the
related group income statement, group statement of comprehensive income, group statement of changes in equity and group cash flow statement for
each of the three years in the period ended 31 December 2013. These financial statements are the responsibility of the Company’s management. Our
responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement.
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 financial statements referred to above present fairly, in all material respects, the group financial position of BP p.l.c. at 31 December
2013, 31 December 2012 and 1 January 2012 and the group results of its operations and its cash flows for each of the three years in the period ended
31 December 2013, in accordance with International Financial Reporting Standards as adopted by the European Union and International Financial
Reporting Standards as issued by the International Accounting Standards Board.
In forming our opinion we have considered the adequacy of the disclosures made in Note 2 to the financial statements concerning the provisions,
future expenditures for which reliable estimates cannot be made and other contingencies related to the Gulf of Mexico oil spill significant event. The
total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the ultimate
exposure and cost to BP will be dependent on many factors. Furthermore, significant uncertainty exists in relation to the amount of claims that will
become payable by BP, the amount of fines that will ultimately be levied on BP (including any determination of BP’s culpability based on any findings of
negligence, gross negligence or wilful misconduct), the outcome of litigation and arbitration proceedings, and any costs arising from any longer-term
environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP. Our opinion is not qualified in respect of these
matters.
As discussed in Note 1 to the consolidated financial statements, the group has changed its accounting policies for employee benefits and interests in
joint arrangements, including related disclosures, as a result of adopting new and revised International Financial Reporting Standards.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), BP p.l.c.’s internal control
over financial reporting as of 31 December 2013, based on criteria established in Internal Control: Revised Guidance for Directors on the Combined
Code as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull guidance) and our report dated 6 March 2014 expressed
an unqualified opinion.
/s/ Ernst & Young LLP
London, England
6 March 2014
1. The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not
involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the
financial statements since they were initially presented on the website.
2. Legislation in the United Kindom governing the preparation and dissemination of financial statements may differ from legislation in other
jurisdictions.
120
BP Annual Report and Form 20-F 2013
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm on the Annual Report on Form 20-F
The Board of Directors and Shareholders of BP p.l.c.
We have audited BP p.l.c.’s internal control over financial reporting as of 31 December 2013, based on criteria established in Internal Control: Revised
Guidance for Directors on the Combined Code as issued by the Institute of Chartered Accountants in England and Wales (the Turnbull guidance).
BP p.l.c.’s management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of
internal control over financial reporting included in the accompanying Management’s report on internal control on page 111. Our responsibility is to
express an opinion on the company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
In our opinion, BP p.l.c. maintained, in all material respects, effective internal control over financial reporting as of 31 December 2013, based on the
Turnbull guidance.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the group balance sheets
of BP p.l.c. as of 31 December 2013 and 2012, and the related group income statement, group statement of comprehensive income, group statement
of changes in equity and group cash flow statement for each of the three years in the period ended 31 December 2013, and our report dated 6 March
2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
London, England
6 March 2014
Consent of independent registered public accounting firm
We consent to the incorporation by reference of our reports dated 6 March 2014, with respect to the group financial statements of BP p.l.c., and the
effectiveness of internal control over financial reporting of BP p.l.c., included in this Annual Report and Form 20-F for the year ended 31 December
2013 in the following Registration Statements:
Registration Statement on Form F-3 (File No. 333-179953) of BP Capital Markets p.l.c. and BP p.l.c.; and
Registration Statements on Form S-8 (File Nos. 333-149778, 333-79399, 333-67206, 333-103924, 333-123482, 333-123483, 333-131583,
333-146868, 333-146870, 333-146873, 333-131584, 333-132619, 333-173136, 333-177423, 333-179406, 333-186463 and 333-186462) of
BP p.l.c.
/s/ Ernst & Young LLP
London, England
6 March 2014
1. The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not
involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the
financial statements since they were initially presented on the website.
2. Legislation in the United Kindom governing the preparation and dissemination of financial statements may differ from legislation in other
jurisdictions.
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BP Annual Report and Form 20-F 2013
121
Group income statement
For the year ended 31 December
Sales and other operating revenues
Earnings from joint ventures – after interest and tax
Earnings from associates – after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expensesb
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
Fair value gain on embedded derivatives
Profit before interest and taxation
Finance costsb
Net finance expense relating to pensions and other post-retirement benefits
Profit before taxation
Taxationb
Profit for the year
Attributable to
BP shareholders
Non-controlling interests
Earnings per share – cents
Profit for the year attributable to BP shareholders
Basic
Diluted
Note
2013
2012a
379,136
447
2,742
777
13,115
396,217
298,351
27,527
7,047
13,510
1,961
3,441
13,070
(459)
31,769
1,068
480
30,221
6,463
23,758
23,451
307
23,758
375,765
260
3,675
1,677
6,697
388,074
292,774
33,926
8,158
12,687
6,275
1,475
13,357
(347)
19,769
1,072
566
18,131
6,880
11,251
11,017
234
11,251
$ million
2011a
375,713
767
4,916
688
4,132
386,216
285,133
24,163
8,280
11,357
2,058
1,520
13,958
(68)
39,815
1,187
400
38,228
12,619
25,609
25,212
397
25,609
123.87
123.12
57.89
57.50
133.35
131.74
7
17
18
8
5
21
7
7
5
10
26
8
30
11
32
32
13
13
a See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 ‘Joint Arrangements’ and the amended IAS 19 ‘Employee Benefits’.
b See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.
122
BP Annual Report and Form 20-F 2013
Group statement of comprehensive income
For the year ended 31 December
Profit for the year
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Note
2013
2012a
23,758
11,251
Currency translation differences
Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on sale
(1,608)
485
of businesses and fixed assets
Available-for-sale investments marked to market
Available-for-sale investments reclassified to the income statement
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement
Cash flow hedges reclassified to the balance sheet
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that may be reclassified
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that will not be reclassified
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
$ million
2011a
25,609
(543)
19
(71)
(3)
44
(195)
(13)
(39)
23
(778)
(5,301)
–
1,467
(3,834)
(4,612)
26
26
26
11,32
30
11,32
22
(172)
(523)
(2,000)
4
17
(24)
147
(4,137)
4,764
2
(1,521)
3,245
(892)
(15)
306
(1)
1,466
62
19
(39)
(170)
2,113
(1,572)
(6)
440
(1,138)
975
22,866
12,226
20,997
32
32
22,574
292
22,866
11,988
238
12,226
20,613
384
20,997
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a See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 ‘Joint Arrangements’, the amended IAS 19 ‘Employee Benefits’ and the amended IAS 1
‘Presentation of Financial Statements’.
Group statement of changes in equitya b
At 1 January 2013
Profit for the year
Other comprehensive income
Total comprehensive income
Dividends
Repurchases of ordinary share capital
Share-based payments, net of tax
Share of equity-accounted entities’ changes in equity,
net of tax
Transactions involving non-controlling interests
At 31 December 2013
At 1 January 2012
Profit for the year
Other comprehensive income
Total comprehensive income
Dividends
Share-based payments, net of tax
Transactions involving non-controlling interests
At 31 December 2012
At 1 January 2011
Profit for the year
Other comprehensive income
Total comprehensive income
Dividends
Share-based payments, net of tax
Transactions involving non-controlling interests
At 31 December 2011
Own
Share
shares
capital
and
and
treasury
capital
shares
reserves
43,513 (21,054)
–
–
–
–
–
83
–
–
–
–
–
143
Foreign
Fair
currency
value
translation
reserve
reserve
5,128 1,775
–
(1,603) (2,470)
(1,603) (2,470)
–
–
–
–
–
–
–
Share-
based
payment
reserve
1,608
–
–
–
–
–
97
Profit
and loss
account
87,576
23,451
3,196
26,647
(5,441)
(6,923)
150
BP
shareholders’
equity
118,546
23,451
(877)
22,574
(5,441)
(6,923)
473
Non-
controlling
interests
1,206
307
(15)
292
(469)
–
–
$ million
Total
equity
119,752
23,758
(892)
22,866
(5,910)
(6,923)
473
–
–
–
–
43,656 (20,971)
–
–
3,525
–
–
73
–
(695) 1,705 102,082
–
–
43,454 (21,323)
–
–
–
–
269
–
43,513 (21,054)
–
–
–
–
59
–
43,448 (21,211)
–
–
–
–
(112)
–
43,454 (21,323)
–
–
–
–
6
–
4,509
–
267
–
619 1,508
619 1,508
–
–
–
5,128 1,775
–
–
–
5,036
–
(527)
(527)
–
–
–
4,509
469
–
(202)
(202)
–
–
–
267
1,582
–
–
–
–
26
–
1,608
1,586
–
–
–
–
(4)
–
1,582
83,079
11,017
(1,156)
9,861
(5,294)
(70)
–
87,576
65,754
25,212
(3,870)
21,342
(4,072)
102
(47)
83,079
73
–
129,302
–
76
1,105
73
76
130,407
111,568
11,017
971
11,988
(5,294)
284
–
118,546
95,082
25,212
(4,599)
20,613
(4,072)
(8)
(47)
111,568
1,017
234
4
238
(82)
–
33
1,206
904
397
(13)
384
(245)
–
(26)
1,017
112,585
11,251
975
12,226
(5,376)
284
33
119,752
95,986
25,609
(4,612)
20,997
(4,317)
(8)
(73)
112,585
a See Note 32 for further information.
b See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 ‘Joint Arrangements’ and the amended IAS 19 ‘Employee Benefits’.
BP Annual Report and Form 20-F 2013
123
Group balance sheet
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Fixed assets
Loans
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Non-controlling interests
Total equity
14
15
16
17
18
20
22
26
11
30
21
22
26
20
23
4
25
26
27
29
4
25
26
27
11
29
30
31 December
2013
31 December
2012a
Note
$ million
1 January
2012a
123,431
12,429
21,653
8,303
13,291
2,635
181,742
824
5,738
5,038
739
611
17
194,709
244
26,073
43,589
3,857
1,315
235
288
14,177
89,778
8,420
98,198
133,690
12,181
22,039
9,199
16,636
1,565
195,310
763
5,985
3,509
922
985
1,376
208,850
216
29,231
39,831
2,675
1,388
512
467
22,520
96,840
–
96,840
125,331
12,190
24,632
8,614
2,998
2,704
176,469
642
5,961
4,294
830
874
12
189,082
247
28,203
37,611
4,507
1,091
456
319
19,635
92,069
19,315
111,384
305,690
300,466
292,907
47,159
2,322
8,960
7,381
1,945
5,045
72,812
–
72,812
4,756
2,225
547
40,811
17,439
26,915
9,778
46,673
2,658
6,875
10,033
2,503
7,587
76,329
846
77,175
2,292
2,723
491
38,767
15,243
30,396
13,627
102,471
103,539
52,000
3,220
6,016
9,039
1,943
11,238
83,456
538
83,994
3,214
3,773
400
35,169
15,220
26,462
12,090
96,328
175,283
180,714
180,322
130,407
119,752
112,585
32
32
32
129,302
1,105
130,407
118,546
1,206
119,752
111,568
1,017
112,585
a See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 ‘Joint Arrangements’ and the amended IAS 19 ‘Employee Benefits’.
C-H Svanberg Chairman
R W Dudley Group Chief Executive
6 March 2014
124
BP Annual Report and Form 20-F 2013
Group cash flow statement
For the year ended 31 December
Operating activities
Profit before taxationb
Adjustments to reconcile profit before taxation to net cash provided by operating activities
Exploration expenditure written off
Depreciation, depletion and amortization
Impairment and (gain) loss on sale of businesses and fixed assets
Earnings from joint ventures and associates
Dividends received from joint ventures and associates
Interest receivable
Interest received
Finance costs
Interest paid
Net finance expense relating to pensions and other post-retirement benefits
Share-based payments
Net operating charge for pensions and other post-retirement benefits, less contributions and
benefit payments for unfunded plans
Net charge for provisions, less payments
(Increase) decrease in inventories
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Income taxes paid
Net cash provided by operating activities
Investing activities
Capital expenditure
Acquisitions, net of cash acquired
Investment in joint ventures
Investment in associates
Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposedc
Proceeds from loan repayments
Net cash used in investing activities
Financing activities
Net issue (repurchase) of shares
Proceeds from long-term financing
Repayments of long-term financing
Net increase (decrease) in short-term debt
Net increase (decrease) in non-controlling interests
Dividends paid
BP shareholders
Non-controlling interests
Net cash provided by (used in) financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Note
2013
2012a
$ million
2011a
30,221
18,131
38,228
10
7
5
8
30
30
3
5
5
12
2,710
13,510
(11,154)
(3,189)
1,391
(314)
173
1,068
(1,084)
480
297
(920)
1,061
(1,193)
(2,718)
(2,932)
(6,307)
745
12,687
(422)
(3,935)
1,763
(379)
175
1,072
(1,166)
566
156
(858)
5,338
(1,720)
2,933
(8,125)
(6,482)
1,024
11,357
(2,074)
(5,683)
5,040
(284)
210
1,187
(1,125)
400
(88)
(1,003)
2,988
(4,079)
(9,860)
(5,957)
(8,063)
21,100
20,479
22,218
(24,520)
(67)
(451)
(4,994)
18,115
3,884
178
(7,855)
(5,358)
8,814
(5,959)
(2,019)
32
(5,441)
(469)
(10,400)
40
2,885
19,635
22,520
(23,222)
(116)
(1,526)
(54)
9,992
1,606
245
(13,075)
122
11,087
(7,177)
(666)
–
(5,294)
(82)
(2,010)
64
5,458
14,177
19,635
(17,978)
(10,909)
(855)
(55)
3,504
(663)
203
(26,753)
74
11,600
(9,102)
2,222
–
(4,072)
(245)
477
(493)
(4,551)
18,728
14,177
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a See Note 1 for information on the restatement of comparative amounts as a result of the adoption of IFRS 11 ‘Joint Arrangements’ and the amended IAS 19 ‘Employee Benefits’.
b 2012 included $709 million of dividends received from TNK-BP. See Note 6 for further information.
c 2011 included the repayment of a deposit received in advance of $3,530 million following the termination of an agreement in respect of the expected sale of our interest in Pan American Energy LLC.
BP Annual Report and Form 20-F 2013
125
Notes on financial statements
Changes to the 2013 financial statements
BP aims for the highest standard of financial reporting and supports the initiatives of the UK Financial Reporting Council and the US Securities and
Exchange Commission to improve understandability and transparency by cutting immaterial ‘clutter’ from financial statements. We continually
review the structure and content of our financial reports. For the 2013 financial statements, to increase their understandability and navigability, we
have changed the grouping of certain notes, and have also sought to remove immaterial disclosures. In applying materiality to the financial
statement disclosures, we consider both the amount and the nature of each item. The main changes compared with the financial statements
included in the BP Annual Report and Form 20-F 2012 are as follows:
• Note 1 Significant accounting policies, judgements, estimates and assumptions – this note includes the critical accounting estimates and
judgements in boxed text following the relevant accounting policy. Last year this information was shown under Critical accounting policies in the
Additional disclosures section of the Directors’ Report.
• Note 2 Significant event – Gulf of Mexico oil spill now contains all of our financial statement note disclosures in respect of the 2010 oil spill. Last
year we also included information in the Provisions and Contingent liabilities notes to the financial statements.
• Note 7 Segmental analysis now includes analysis of depreciation, depletion and amortization and production and similar taxes, previously provided
in separate notes.
• Note 8 Income statement analysis now combines a number of notes previously provided separately, simplifying the presentation while retaining
materially the same content.
• Note 15 Goodwill and impairment review of goodwill now contains the disclosures related to impairment testing of goodwill, which were provided
in a separate note last year.
• Note 19 Financial instruments and financial risk factors and Note 26 Derivative financial instruments have been rationalized to focus only on the
material matters.
• Note 38 Subsidiaries, joint arrangements and associates now lists only the most significant entities.
• A separate share-based payment note is no longer presented. The share-based payment expense for the year is included in Note 33 Employee
costs and numbers and information on the dilutive impact of employee share plans is included in Note 13 Earnings per ordinary share.
1. Significant accounting policies, judgements, estimates and assumptions
Authorization of financial statements and statement of compliance with International Financial Reporting Standards
The consolidated financial statements of the BP group for the year ended 31 December 2013 were approved and signed by the group chief executive
and chairman on 6 March 2014 having been duly authorized to do so by the board of directors. BP p.l.c. is a public limited company incorporated and
domiciled in England and Wales. The consolidated financial statements have been prepared in accordance with International Financial Reporting
Standards (IFRS) as issued by the International Accounting Standards Board (IASB), IFRS as adopted by the European Union (EU) and in accordance
with the provisions of the UK Companies Act 2006. IFRS as adopted by the EU differs in certain respects from IFRS as issued by the IASB, however,
the differences have no impact on the group’s consolidated financial statements for the years presented. The significant accounting policies and critical
accounting judgements, estimates and assumptions of the group are set out below.
Basis of preparation
The consolidated financial statements have been prepared in accordance with IFRS and IFRS Interpretations Committee (IFRIC) interpretations issued
and effective for the year ended 31 December 2013. The standards and interpretations adopted in the year, and the corresponding impact on the
financial statements, are described further on page 137.
The accounting policies that follow have been consistently applied to all years presented. Where retrospective restatements were required as a result
of the implementation of new accounting standards or changes to existing accounting standards, these have been applied to all comparative years
presented.
Subsequent to releasing our unaudited fourth quarter and full year 2013 results announcement dated 4 February 2014, a minor amendment has been
made to the split of the Upstream replacement cost profit before interest and tax between US and non-US. The amount reported for US for the year
has been reduced by $0.2 billion to $3.1 billion and the amount reported for non-US has been increased by $0.2 billion to $28.9 billion. Similarly,
amendments have also been made to the geographical analysis for revenues and capital expenditure and acquisitions. There was no impact on the
group’s profit or loss, net assets or cash flows for the year.
The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where
otherwise indicated.
Critical accounting policies: use of judgements, estimates and assumptions
Inherent in the application of many of the accounting policies used in preparing the financial statements is the need for BP management to make
judgements, estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues and expenses during the period. Actual outcomes could differ from the
estimates and assumptions used. The critical accounting judgements and estimates that could have a significant impact on the results of the group are
set out in boxed text below, and should be read in conjunction with the information provided in the Notes on financial statements. The areas requiring
the most significant judgement and estimation in the preparation of the consolidated financial statements are in relation to acquisitions of interests in
other entities, oil and natural gas accounting, including the estimation of reserves, the recoverability of asset carrying values, derivative financial
instruments, including the application of hedge accounting, provisions and contingencies, in particular provisions and contingencies related to the Gulf
of Mexico oil spill, pensions and other post-retirement benefits and taxation.
Basis of consolidation
The group financial statements consolidate the financial statements of BP p.l.c. and the entities it controls (its subsidiaries) drawn up to 31 December
each year. Control of an investee exists when the investor is exposed, or has rights, to variable returns from its involvement with the investee and has
the ability to affect those returns through its power over the investee. To have power over an investee, the investor must have existing rights that give
it the current ability to direct the relevant activities of the investee. Subsidiaries are consolidated from the date of their acquisition, being the date on
which the group obtains control, and continue to be consolidated until the date that such control ceases. The financial statements of subsidiaries are
prepared for the same reporting year as the parent company, using consistent accounting policies. Intercompany balances and transactions, including
unrealized profits arising from intragroup transactions, have been eliminated. Unrealized losses are eliminated unless the transaction provides evidence
of an impairment of the asset transferred. Non-controlling interests represent the equity in subsidiaries that is not attributable, directly or indirectly, to
the group.
126
BP Annual Report and Form 20-F 2013
1. Significant accounting policies, judgements, estimates and assumptions – continued
Interests in other entities
Business combinations and goodwill
A business combination is a transaction or other event in which an acquirer obtains control of one or more businesses. A business is an integrated set
of activities and assets that is capable of being conducted and managed for the purpose of providing a return in the form of dividends or lower costs or
other economic benefits directly to investors or other owners or participants. A business consists of inputs and processes applied to those inputs that
have the ability to create outputs.
Business combinations are accounted for using the acquisition method. The identifiable assets acquired and liabilities assumed are measured at their
fair values at the acquisition date. The cost of an acquisition is measured as the aggregate of the consideration transferred, measured at acquisition-
date fair value, and the amount of any non-controlling interest in the acquiree. Non-controlling interests are stated either at fair value or at the
proportionate share of the recognized amounts of the acquiree’s identifiable net assets. Acquisition costs incurred are expensed and included in
distribution and administration expenses.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred, the amount recognized for any non-controlling interest
and the acquisition-date fair values of any previously held interest in the acquiree over the fair value of the identifiable assets acquired and liabilities
assumed at the acquisition date.
At the acquisition date, any goodwill acquired is allocated to each of the cash-generating units, or groups of cash-generating units, expected to benefit
from the combination’s synergies.
Following initial recognition, goodwill is measured at cost less any accumulated impairment losses. Goodwill is reviewed for impairment annually or
more frequently if events or changes in circumstances indicate the recoverable amount of the cash-generating unit to which the goodwill relates
should be assessed. Where the recoverable amount of the cash-generating unit is less than the carrying amount, an impairment loss is recognized. An
impairment loss recognized for goodwill is not reversed in a subsequent period.
Goodwill arising on business combinations prior to 1 January 2003 is stated at the previous carrying amount, less subsequent impairments, under UK
generally accepted accounting practice.
Goodwill may also arise upon investments in joint ventures and associates, being the surplus of the cost of investment over the group’s share of the
net fair value of the identifiable assets and liabilities. Such goodwill is recorded within the corresponding investment in joint ventures and associates,
and any impairment of the investment is included within the group’s share of earnings from joint ventures and associates.
Interests in joint arrangements
A joint arrangement is an arrangement of which two or more parties have joint control. Joint control is the contractually agreed sharing of control of an
arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.
A joint venture is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement.
The results, assets and liabilities of a joint venture are incorporated in these financial statements using the equity method of accounting as described
below.
Certain of the group’s activities, particularly in the Upstream segment, are conducted through joint operations, which are joint arrangements whereby
the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. BP
recognizes, on a line-by-line basis in the consolidated financial statements, its share of the assets, liabilities and expenses of these joint operations
incurred jointly with the other partners, along with the group’s income from the sale of its share of the output and any liabilities and expenses that the
group has incurred in relation to the joint operation.
Interests in associates
An associate is an entity over which the group has significant influence, through the power to participate in the financial and operating policy decisions
of the investee, but which is not a subsidiary or a joint arrangement. The results, assets and liabilities of an associate are incorporated in these financial
statements using the equity method of accounting as described below.
Significant estimate or judgement
Judgement is required in assessing the level of control obtained in a transaction to acquire an interest in another entity: depending upon the facts
and circumstances in each case, BP may obtain control, joint control or significant influence over the entity or arrangement. Transactions which give
BP control of a business are business combinations. If BP obtains joint control of an arrangement, judgement is also required to assess whether the
arrangement is a joint operation or a joint venture. If BP has neither control nor joint control, it may be in a position to exercise significant influence
over the entity, which is then accounted for as an associate.
Accounting for business combinations and acquisitions of investments in equity-accounted joint ventures and associates requires judgements and
estimates to be made in order to determine the fair value of the consideration transferred, together with the fair values of the assets acquired and
the liabilities assumed in a business combination, or the identifiable assets and liabilities of the equity-accounted entity at the acquisition date. The
group uses all available information, including external valuations and appraisals where appropriate, to determine these fair values. If necessary, the
group has up to one year from the acquisition date to finalize the determinations of fair value for business combinations.
At 31 December 2013, and since the transaction described in Note 6 concluded on 21 March 2013, BP owned 19.75% of the voting shares of OJSC
Oil Company Rosneft (Rosneft), a Russian oil and gas company. The Russian federal government, through its investment company OJSC
Rosneftegaz, owned 69.5% of the voting shares of Rosneft at 31 December 2013. BP uses the equity method of accounting for its investment in
Rosneft because under IFRS it is considered to have significant influence. Significant influence is defined as the power to participate in the financial
and operating policy decisions of the investee but is not control or joint control. IFRS identifies several indicators that may provide evidence of
significant influence, including representation on the board of directors of the investee and participation in policy-making processes. BP’s group chief
executive, Bob Dudley, has been elected to the board of directors of Rosneft, he is a member of the Rosneft board’s Strategic Planning Committee
and he participated in Rosneft’s steering committee to integrate TNK-BP. Furthermore, under the Rosneft Charter BP has the right to nominate a
second director to Rosneft’s nine-person board of directors for election at a general meeting of shareholders should it choose to do so in the future.
In addition, BP holds the voting rights at general meetings of shareholders conferred by its 19.75% stake in Rosneft. In management’s judgement,
the group has significant influence over Rosneft, as defined by the relevant accounting standard, and the investment is therefore accounted for as an
associate. BP’s share of Rosneft’s oil and natural gas reserves is included in the estimated net proved reserves of equity-accounted entities.
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BP Annual Report and Form 20-F 2013
127
1. Significant accounting policies, judgements, estimates and assumptions – continued
The equity method of accounting
Under the equity method, the investment in an equity-accounted entity (joint venture or associate) is carried on the balance sheet at cost plus post-
acquisition changes in the group’s share of net assets of the equity-accounted entity, less distributions received and less any impairment in value of the
investment. Loans advanced to equity-accounted entities that have the characteristics of equity financing are also included in the investment on the
group balance sheet. The group income statement reflects the group’s share of the results after tax of the equity-accounted entity, adjusted to account
for depreciation, amortization and any impairment of the equity-accounted entity’s assets based on their fair values at the date of acquisition.
The group statement of comprehensive income includes the group’s share of the equity-accounted entity’s other comprehensive income. The group’s
share of amounts recognized directly in equity by an equity-accounted entity is recognized directly in the group’s statement of changes in equity.
Financial statements of equity-accounted entities are prepared for the same reporting year as the group. Where material differences arise, adjustments
are made to those financial statements to bring the accounting policies used into line with those of the group.
Unrealized gains on transactions between the group and its equity-accounted entities are eliminated to the extent of the group’s interest in the equity-
accounted entity. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred.
The group assesses investments in equity-accounted entities for impairment whenever events or changes in circumstances indicate that the carrying
value may not be recoverable. If any such indication of impairment exists, the carrying amount of the investment is compared with its recoverable
amount, being the higher of its fair value less costs to sell and value in use. Where the carrying amount exceeds the recoverable amount, the
investment is written down to its recoverable amount.
The group ceases to use the equity method of accounting on the date from which it no longer has joint control over the joint venture or significant
influence over the associate, or when the interest becomes classified as an asset held for sale.
Segmental reporting
The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the chief operating
decision maker in deciding how to allocate resources and in assessing performance.
On 22 October 2012, BP announced that it had signed heads of terms for a proposed transaction to sell its 50% share in TNK-BP to Rosneft. Following
this agreement, BP’s investment in TNK-BP met the criteria to be classified as held for sale. On 21 March 2013, the disposal of BP’s investment in
TNK-BP completed and BP increased its investment in Rosneft. See Note 6 for further information. BP’s investment in Rosneft is reported as a
separate operating segment since that date, reflecting the way in which the investment is managed.
A separate organization within the group deals with the ongoing response to the Gulf of Mexico oil spill. This organization reports directly to the group
chief executive and its costs are excluded from the results of the operating segments. Under IFRS its costs are presented as a reconciling item
between the sum of the results of the reportable segments and the group results.
The accounting policies of the operating segments are the same as the group’s accounting policies described in this note, except that IFRS requires
that the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker.
For BP, this measure of profit or loss is replacement cost profit before interest and tax which reflects the replacement cost of supplies by excluding
from profit inventory holding gains and losses. Replacement cost profit for the group is not a recognized measure under IFRS. For further information
see Note 7.
Foreign currency translation
The functional currency is the currency of the primary economic environment in which an entity operates and is normally the currency in which the
entity primarily generates and expends cash.
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency by applying the
rate of exchange ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the
functional currency at the rate of exchange ruling at the balance sheet date. Any resulting exchange differences are included in the income statement.
Non-monetary assets and liabilities, other than those measured at fair value, are not retranslated subsequent to initial recognition.
In the consolidated financial statements, the assets and liabilities of non-US dollar functional currency subsidiaries, joint ventures and associates,
including related goodwill, are translated into US dollars at the rate of exchange ruling at the balance sheet date. The results and cash flows of non-US
dollar functional currency subsidiaries, joint ventures and associates are translated into US dollars using average rates of exchange. Exchange
adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency subsidiaries, joint ventures
and associates are translated into US dollars are taken to a separate component of equity and reported in the statement of comprehensive income.
Exchange gains and losses arising on long-term intragroup foreign currency borrowings used to finance the group’s non-US dollar investments are also
taken to other comprehensive income. On disposal or partial disposal of a non-US dollar functional currency subsidiary, joint venture or associate, the
deferred cumulative amount of exchange gains and losses recognized in equity relating to that particular non-US dollar operation is reclassified to the
income statement.
Non-current assets held for sale
Non-current assets and disposal groups classified as held for sale are measured at the lower of carrying amount and fair value less costs to sell.
Non-current assets and disposal groups are classified as held for sale if their carrying amounts will be recovered through a sale transaction rather than
through continuing use. This condition is regarded as met only when the sale is highly probable and the asset or disposal group is available for
immediate sale in its present condition subject only to terms that are usual and customary for sales of such assets. Management must be committed
to the sale, which should be expected to qualify for recognition as a completed sale within one year from the date of classification as held for sale.
Property, plant and equipment and intangible assets are not depreciated once classified as held for sale. The group ceases to use the equity method of
accounting from the date on which an interest in a joint venture or associate becomes held for sale. If a non-current asset or disposal group has been
classified as held for sale, but subsequently ceases to meet the criteria to be classified as held for sale, the group ceases to classify the asset or
disposal group as held for sale. Non-current assets and disposal groups that cease to be classified as held for sale are measured at the lower of the
carrying amount before the asset or disposal group was classified as held for sale (adjusted for any depreciation, amortization or revaluation that would
have been recognized had the asset or disposal group not been classified as held for sale) and its recoverable amount at the date of the subsequent
decision not to sell. Except for any interests in equity-accounted entities that cease to be classified as held for sale, any adjustment to the carrying
amount is recognized in profit or loss in the period in which the asset ceases to be classified as held for sale. When an interest in an equity-accounted
entity ceases to be classified as held for sale, it is accounted for using the equity method as from the date of its classification as held for sale and the
financial statements for the periods since classification as held for sale are amended accordingly.
128
BP Annual Report and Form 20-F 2013
1. Significant accounting policies, judgements, estimates and assumptions – continued
Intangible assets
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer software,
patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses.
For information on accounting for expenditures on the exploration for and evaluation of oil and natural gas resources, see the accounting policy for oil
and natural gas exploration, appraisal and development expenditure below.
Intangible assets acquired separately from a business are carried initially at cost. The initial cost is the aggregate amount paid and the fair value of any
other consideration given to acquire the asset. An intangible asset acquired as part of a business combination is measured at fair value at the date of
acquisition and is recognized separately from goodwill if the asset is separable or arises from contractual or other legal rights.
Intangible assets with a finite life are amortized on a straight-line basis over their expected useful lives. For patents, licences and trademarks, expected
useful life is the shorter of the duration of the legal agreement and economic useful life, and can range from three to 15 years. Computer software
costs generally have a useful life of three to five years.
The expected useful lives of assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.
The carrying value of intangible assets is reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not
be recoverable.
Oil and natural gas exploration, appraisal and development expenditure
Oil and natural gas exploration, appraisal and development expenditure is accounted for using the principles of the successful efforts method of
accounting.
Licence and property acquisition costs
Exploration licence and leasehold property acquisition costs are capitalized within intangible assets and are reviewed at each reporting date to confirm
that there is no indication that the carrying amount exceeds the recoverable amount. This review includes confirming that exploration drilling is still
under way or firmly planned or that it has been determined, or work is under way to determine, that the discovery is economically viable based on a
range of technical and commercial considerations and sufficient progress is being made on establishing development plans and timing. If no future
activity is planned, the remaining balance of the licence and property acquisition costs is written off. Lower value licences are pooled and amortized on
a straight-line basis over the estimated period of exploration. Upon recognition of proved reserves and internal approval for development, the relevant
expenditure is transferred to property, plant and equipment.
Exploration and appraisal expenditure
Geological and geophysical exploration costs are charged against income as incurred. Costs directly associated with an exploration well are initially
capitalized as an intangible asset until the drilling of the well is complete and the results have been evaluated. These costs include employee
remuneration, materials and fuel used, rig costs and payments made to contractors. If potentially commercial quantities of hydrocarbons are not found,
the exploration well is written off as a dry hole. If hydrocarbons are found and, subject to further appraisal activity, are likely to be capable of
commercial development, the costs continue to be carried as an asset.
Costs directly associated with appraisal activity, undertaken to determine the size, characteristics and commercial potential of a reservoir following the
initial discovery of hydrocarbons, including the costs of appraisal wells where hydrocarbons were not found, are initially capitalized as an intangible
asset. When proved reserves of oil and natural gas are determined and development is approved by management, the relevant expenditure is
transferred to property, plant and equipment.
Development expenditure
Expenditure on the construction, installation and completion of infrastructure facilities such as platforms, pipelines and the drilling of development
wells, including service and unsuccessful development or delineation wells, is capitalized within property, plant and equipment and is depreciated from
the commencement of production as described below in the accounting policy for property, plant and equipment.
Significant estimate or judgement
The determination of whether potentially economic oil and natural gas reserves have been discovered by an exploration well is usually made within
one year after well completion, but can take longer, depending on the complexity of the geological structure. Exploration wells that discover
potentially economic quantities of oil and natural gas and are in areas where major capital expenditure (e.g. offshore platform or a pipeline) would be
required before production could begin, and where the economic viability of that major capital expenditure depends on the successful completion of
further exploration work in the area, remain capitalized on the balance sheet as long as additional exploration appraisal work is under way or firmly
planned.
It is not unusual to have exploration wells and exploratory-type stratigraphic test wells remaining suspended on the balance sheet for several years
while additional appraisal drilling and seismic work on the potential oil and natural gas field is performed or while the optimum development plans
and timing are established. All such carried costs are subject to regular technical, commercial and management review on at least an annual basis to
confirm the continued intent to develop, or otherwise extract value from, the discovery. Where this is no longer the case, the costs are immediately
expensed.
Property, plant and equipment
Property, plant and equipment is stated at cost, less accumulated depreciation and accumulated impairment losses. The initial cost of an asset
comprises its purchase price or construction cost, any costs directly attributable to bringing the asset into the location and condition necessary for it to
be capable of operating in the manner intended by management, the initial estimate of any decommissioning obligation, if any, and, for assets that
necessarily take a substantial period of time to get ready for their intended use, borrowing costs. The purchase price or construction cost is the
aggregate amount paid and the fair value of any other consideration given to acquire the asset. The capitalized value of a finance lease is also included
within property, plant and equipment. Exchanges of assets are measured at fair value unless the exchange transaction lacks commercial substance or
the fair value of neither the asset received nor the asset given up is reliably measurable. The cost of the acquired asset is measured at the fair value of
the asset given up, unless the fair value of the asset received is more clearly evident. Where fair value is not used, the cost of the acquired asset is
measured at the carrying amount of the asset given up. The gain or loss on derecognition of the asset given up is recognized in profit or loss.
Expenditure on major maintenance refits or repairs comprises the cost of replacement assets or parts of assets, inspection costs and overhaul costs.
Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the
item will flow to the group, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized. Inspection costs associated
with major maintenance programmes are capitalized and amortized over the period to the next inspection. Overhaul costs for major maintenance
programmes, and all other maintenance costs are expensed as incurred.
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Oil and natural gas properties, including related pipelines, are depreciated using a unit-of-production method. The cost of producing wells is amortized
over proved developed reserves. Licence acquisition, common facilities and future decommissioning costs are amortized over total proved reserves.
The unit-of-production rate for the depreciation of common facilities takes into account expenditures incurred to date, together with estimated future
capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed through these common facilities.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s other
property, plant and equipment are as follows:
Land improvements
Buildings
Refineries
Petrochemicals plants
Pipelines
Service stations
Office equipment
Fixtures and fittings
15 to 25 years
20 to 50 years
20 to 30 years
20 to 30 years
10 to 50 years
15 years
3 to 7 years
5 to 15 years
The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for
prospectively.
The carrying amount of property, plant and equipment is reviewed for impairment whenever events or changes in circumstances indicate the carrying
value may not be recoverable.
An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the continued
use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal proceeds and the
carrying amount of the item) is included in the income statement in the period in which the item is derecognized.
Significant estimate or judgement
The determination of the group’s estimated oil and natural gas reserves requires significant judgements and estimates to be applied and these are
regularly reviewed and updated. Factors such as the availability of geological and engineering data, reservoir performance data, acquisition and
divestment activity, drilling of new wells and commodity prices all impact on the determination of the group’s estimates of its oil and natural gas
reserves. BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments
based on conventional industry practice and regulatory requirements.
The estimation of oil and natural gas reserves and BP’s process to manage reserves bookings is described in Supplementary information on oil and
natural gas on page 200, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are provided on
page 245.
Estimates of oil and natural gas reserves are used to calculate depreciation, depletion and amortization charges for the group’s oil and gas properties.
The impact of changes in estimated proved reserves is dealt with prospectively by amortizing the remaining carrying value of the asset over the
expected future production. Oil and natural gas reserves also have a direct impact on the assessment of the recoverability of asset carrying values
reported in the financial statements. If proved reserves estimates are revised downwards, earnings could be affected by higher depreciation
expense or an immediate write-down of the property’s carrying value.
The 2013 movements in proved reserves are reflected in the tables showing movements in oil and natural gas reserves by region in Supplementary
information on oil and natural gas (unaudited) on page 200. Information on the carrying amounts of the group’s oil and natural gas properties,
together with the amounts recognized in the income statement as depreciation, depletion and amortization is contained in Note 10 and Note 7
respectively.
Impairment of intangible assets and property, plant and equipment
The group assesses assets or groups of assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an
asset may not be recoverable, for example, changes in the group’s business plans, changes in commodity prices leading to sustained unprofitable
performance, low plant utilization, evidence of physical damage or, for oil and gas assets, significant downward revisions of estimated reserves or
increases in estimated future development expenditure. If any such indication of impairment exists, the group makes an estimate of the asset’s
recoverable amount. Individual assets are grouped for impairment assessment purposes at the lowest level at which there are identifiable cash flows
that are largely independent of the cash flows of other groups of assets. An asset group’s recoverable amount is the higher of its fair value less costs
to sell and its value in use. Where the carrying amount of an asset group exceeds its recoverable amount, the asset group is considered impaired and
is written down to its recoverable amount. In assessing value in use, the estimated future cash flows are adjusted for the risks specific to the asset
group and are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money. Fair
value less costs to sell is identified as the price that would be received to sell the asset in an orderly transaction between market participants and does
not reflect the effects of factors that may be specific to the entity and not applicable to entities in general.
An assessment is made at each reporting date as to whether there is any indication that previously recognized impairment losses may no longer exist
or may have decreased. If such an indication exists, the recoverable amount is estimated. A previously recognized impairment loss is reversed only if
there has been a change in the estimates used to determine the asset’s recoverable amount since the last impairment loss was recognized. If that is
the case, the carrying amount of the asset is increased to its recoverable amount. That increased amount cannot exceed the carrying amount that
would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Such reversal is recognized in
profit or loss. After such a reversal, the depreciation charge is adjusted in future periods to allocate the asset’s revised carrying amount, less any
residual value, on a systematic basis over its remaining useful life.
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Significant estimate or judgement
Determination as to whether, and how much, an asset is impaired involves management estimates on highly uncertain matters such as future
commodity prices, the effects of inflation on operating expenses, discount rates, production profiles and the outlook for global or regional market
supply-and-demand conditions for crude oil, natural gas and refined products.
For oil and natural gas properties, the expected future cash flows are estimated using management’s best estimate of future oil and natural gas
prices and reserves volumes. Prices for oil and natural gas used for future cash flow calculations are based on market prices for the first five years
and the group’s long-term price assumptions thereafter. As at 31 December 2013, the group’s long-term price assumptions were $90 per barrel for
Brent and $6.50/mmBtu for Henry Hub (2012 $90 per barrel and $6.50/mmBtu). These long-term price assumptions are subject to periodic review
and revision. The estimated future level of production is based on assumptions about future commodity prices, production and development costs,
field decline rates, current fiscal regimes and other factors.
For value in use calculations, future cash flows are adjusted for risks specific to the cash-generating unit and are discounted using a pre-tax discount
rate. The discount rate is derived from the group’s post-tax weighted average cost of capital and is adjusted where applicable to take into account
any specific risks relating to the country where the cash-generating unit is located, although other rates may be used if appropriate to the specific
circumstances. In 2013 the rates ranged from 12% to 14% nominal (2012 12% to 14% nominal). The discount rates applied in assessments of
impairment are reassessed each year. In cases where fair value less costs to sell is used to determine the recoverable amount of an asset, where
recent market transactions for the asset are not available for reference, accounting judgements are made about the assumptions market participants
would use when pricing the asset. Fair value less costs to sell may be determined based on similar recent market transaction data or using
discounted cash flow techniques. Where discounted cash flow analyses are used to calculate fair value less costs to sell, the discount rate used is
the group’s post-tax weighted average cost of capital.
Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in a business
combination. The group carries goodwill of approximately $12.2 billion on its balance sheet (2012 $12.2 billion), principally relating to the Atlantic
Richfield, Burmah Castrol, Devon Energy and Reliance transactions. In testing goodwill for impairment, the group uses a similar approach to that
described above for asset impairment. If there are low oil or natural gas prices or refining margins or marketing margins for an extended period, the
group may need to recognize significant goodwill impairment charges.
The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and development
expenditure above.
Details of impairment charges recognized in the income statement are provided in Note 5 and details on the carrying amounts of assets are shown
in Note 14, Note 15 and Note 16.
Inventories
Inventories, other than inventory held for trading purposes, are stated at the lower of cost and net realizable value. Cost is determined by the first-in
first-out method and comprises direct purchase costs, cost of production, transportation and manufacturing expenses. Net realizable value is
determined by reference to prices existing at the balance sheet date.
Inventories held for trading purposes are stated at fair value less costs to sell and any changes in fair value are recognized in the income statement.
Supplies are valued at cost to the group mainly using the average method or net realizable value, whichever is the lower.
Leases
Finance leases, which transfer to the group substantially all the risks and benefits incidental to ownership of the leased item, are capitalized at the
commencement of the lease term at the fair value of the leased item or, if lower, at the present value of the minimum lease payments. Finance
charges are allocated to each period so as to achieve a constant rate of interest on the remaining balance of the liability and are charged directly against
income.
Capitalized leased assets are depreciated over the shorter of the estimated useful life of the asset or the lease term. Operating lease payments are
recognized as an expense in the income statement on a straight-line basis over the lease term. For both finance and operating leases, contingent rents
are recognized in the income statement in the period in which they are incurred.
Financial assets
Financial assets are classified as loans and receivables; financial assets at fair value through profit or loss; derivatives designated as hedging
instruments in an effective hedge; held-to-maturity financial assets; or as available-for-sale financial assets, as appropriate. Financial assets include cash
and cash equivalents, trade receivables, other receivables, loans, other investments, and derivative financial instruments. The group determines the
classification of its financial assets at initial recognition. Financial assets are recognized initially at fair value, normally being the transaction price plus, in
the case of financial assets not at fair value through profit or loss, directly attributable transaction costs.
The subsequent measurement of financial assets depends on their classification, as follows:
Loans and receivables
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are
carried at amortized cost using the effective interest method if the time value of money is significant. Gains and losses are recognized in income when
the loans and receivables are derecognized or impaired, as well as through the amortization process. This category of financial assets includes trade
and other receivables. Cash and cash equivalents are short-term highly liquid investments that are readily convertible to known amounts of cash, are
subject to insignificant risk of changes in value and have a maturity of three months or less from the date of acquisition.
Financial assets at fair value through profit or loss
Financial assets at fair value through profit or loss are carried on the balance sheet at fair value with gains or losses recognized in the income
statement. Derivatives, other than those designated as effective hedging instruments, are classified as held for trading and are included in this
category.
Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the
accounting policy for derivative financial instruments and hedging activities.
Held-to-maturity financial assets
Held-to-maturity financial assets are non-derivative financial assets with fixed or determinable payments and fixed maturity that management has the
positive intention and ability to hold to maturity. They are measured at amortized cost using the effective interest method, less any impairment.
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Available-for-sale financial assets
Available-for-sale financial assets are those non-derivative financial assets that are not classified as loans and receivables, financial assets at fair value
through profit or loss, or held-to-maturity financial assets. After initial recognition, available-for-sale financial assets are measured at fair value, with
gains or losses recognized within other comprehensive income, except for impairment losses, foreign exchange gains or losses and any changes in fair
value arising from revised estimates of future cash flows, which are recognized in profit or loss.
Impairment of financial assets
The group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired.
Loans and receivables
If there is objective evidence that an impairment loss on loans and receivables carried at amortized cost has been incurred, the amount of the loss is
measured as the difference between the asset’s carrying amount and the present value of estimated future cash flows discounted at the financial
asset’s original effective interest rate. The carrying amount of the asset is reduced, with the amount of the loss recognized in the income statement.
Significant estimate or judgement
Judgements are required in assessing the recoverability of overdue trade receivables, such as those in Egypt (see Note 19 for further details), and
determining whether a provision against the future recoverability of those receivables is required. Factors considered include the credit rating of the
counterparty, the amount and timing of anticipated future payments and any possible actions that can be taken to mitigate the risk of non-payment.
See Note 19 for information on overdue receivables.
Financial liabilities
Financial liabilities are classified as financial liabilities at fair value through profit or loss; derivatives designated as hedging instruments in an effective
hedge; or as financial liabilities measured at amortized cost, as appropriate. Financial liabilities include trade and other payables, accruals, most items of
finance debt and derivative financial instruments. The group determines the classification of its financial liabilities at initial recognition. The
measurement of financial liabilities depends on their classification, as follows:
Financial liabilities at fair value through profit or loss
Financial liabilities at fair value through profit or loss are carried on the balance sheet at fair value with gains or losses recognized in the income
statement. Derivatives, other than those designated as effective hedging instruments, are classified as held for trading and are included in this
category.
Derivatives designated as hedging instruments in an effective hedge
Such derivatives are carried on the balance sheet at fair value. The treatment of gains and losses arising from revaluation is described below in the
accounting policy for derivative financial instruments and hedging activities.
Financial liabilities measured at amortized cost
All other financial liabilities are initially recognized at fair value. For interest-bearing loans and borrowings this is the fair value of the proceeds received
net of issue costs associated with the borrowing.
After initial recognition, other financial liabilities are subsequently measured at amortized cost using the effective interest method. Amortized cost is
calculated by taking into account any issue costs, and any discount or premium on settlement. Gains and losses arising on the repurchase, settlement
or cancellation of liabilities are recognized respectively in interest and other income and finance costs.
This category of financial liabilities includes trade and other payables and finance debt.
Derivative financial instruments and hedging activities
The group uses derivative financial instruments to manage certain exposures to fluctuations in foreign currency exchange rates, interest rates and
commodity prices as well as for trading purposes. Such derivative financial instruments are initially recognized at fair value on the date on which a
derivative contract is entered into and are subsequently remeasured at fair value. Derivatives relating to unquoted equity instruments are carried at cost
where it is not possible to reliably measure their fair value subsequent to initial recognition. Derivatives are carried as assets when the fair value is
positive and as liabilities when the fair value is negative.
Contracts to buy or sell a non-financial item that can be settled net in cash or another financial instrument, or by exchanging financial instruments as if
the contracts were financial instruments, with the exception of contracts that were entered into and continue to be held for the purpose of the receipt
or delivery of a non-financial item in accordance with the group’s expected purchase, sale or usage requirements, are accounted for as financial
instruments. Contracts to buy or sell equity investments, including investments in associates, are also financial instruments. Gains or losses arising
from changes in the fair value of derivatives that are not designated as effective hedging instruments are recognized in the income statement.
If, at inception of a contract, the valuation cannot be supported by observable market data, any gain or loss determined by the valuation methodology is
not recognized in the income statement but is deferred on the balance sheet and is commonly known as ‘day-one profit or loss’. This deferred gain or
loss is recognized in the income statement over the life of the contract until substantially all the remaining contract term can be valued using
observable market data at which point any remaining deferred gain or loss is recognized in the income statement. Changes in valuation from the initial
valuation are recognized immediately through the income statement.
For the purpose of hedge accounting, hedges are classified as:
• Fair value hedges when hedging exposure to changes in the fair value of a recognized asset or liability.
• Cash flow hedges when hedging exposure to variability in cash flows that is either attributable to a particular risk associated with a recognized asset
or liability or a highly probable forecast transaction.
Hedge relationships are formally designated and documented at inception, together with the risk management objective and strategy for undertaking
the hedge. The documentation includes identification of the hedging instrument, the hedged item or transaction, the nature of the risk being hedged,
and how the entity will assess the hedging instrument effectiveness in offsetting the exposure to changes in the hedged item’s fair value or cash flows
attributable to the hedged risk. Such hedges are expected at inception to be highly effective in achieving offsetting changes in fair value or cash flows.
Hedges meeting the criteria for hedge accounting are accounted for as follows:
Fair value hedges
The change in fair value of a hedging derivative is recognized in profit or loss. The change in the fair value of the hedged item attributable to the risk
being hedged is recorded as part of the carrying value of the hedged item and is also recognized in profit or loss.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
The group applies fair value hedge accounting for hedging fixed interest rate risk on borrowings. The gain or loss relating to the effective portion of the
interest rate swap is recognized in the income statement within finance costs, offsetting the amortization of the interest on the underlying borrowings.
If the criteria for hedge accounting are no longer met, or if the group revokes the designation, the adjustment to the carrying amount of a hedged item
for which the effective interest method is used is amortized to profit or loss over the period to maturity.
Cash flow hedges
For cash flow hedges, the effective portion of the gain or loss on the hedging instrument is recognized within other comprehensive income, while the
ineffective portion is recognized in profit or loss. Amounts taken to other comprehensive income are transferred to the income statement when the
hedged transaction affects profit or loss. The gain or loss relating to the effective portion of interest rate swaps hedging variable rate borrowings is
recognized in the income statement within finance costs.
Where the hedged item is the cost of a non-financial asset or liability, such as a forecast transaction for the purchase of property, plant and equipment,
the amounts recognized within other comprehensive income are transferred to the initial carrying amount of the non-financial asset or liability. Where
the hedged item is an equity investment, such as an investment in an associate, the amounts recognized in other comprehensive income remain in the
separate component of equity until the investment is sold or impaired.
If the hedging instrument expires or is sold, terminated or exercised without replacement or rollover, or if its designation as a hedge is revoked,
amounts previously recognized within other comprehensive income remain in equity until the forecast transaction occurs and are transferred to the
income statement or to the initial carrying amount of a non-financial asset or liability as above.
Significant estimate or judgement
The decision as to whether to apply hedge accounting or not can have a significant impact on the group’s financial statements. Cash flow and fair
value hedge accounting is applied to certain of the group’s finance debt-related derivatives in the normal course of business. In addition, the financial
statements reflect the application of cash flow hedge accounting to certain of the contracts signed in October 2012 for BP to sell its investment in
TNK-BP and obtain an additional shareholding in Rosneft, which were accounted for as derivatives under IFRS. We applied ‘all-in-one’ cash flow
hedge accounting to the contracts to acquire shares in Rosneft, resulting in a pre-tax loss of $2,061 million being recognized in other comprehensive
income for the year (2012 pre-tax gain of $1,410 million). See Note 26 for further information.
Embedded derivatives
Derivatives embedded in other financial instruments or other host contracts are treated as separate derivatives when their risks and characteristics are
not closely related to those of the host contract. Contracts are assessed for embedded derivatives when the group becomes a party to them, including
at the date of a business combination. Embedded derivatives are measured at fair value at each balance sheet date. Any gains or losses arising from
changes in fair value are taken directly to the income statement.
Fair value measurement
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. The
group categorizes assets and liabilities measured at fair value into one of three levels depending on the ability to observe inputs employed in their
measurement. Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Level 2 inputs are inputs that are observable, either
directly or indirectly, other than quoted prices included within level 1 for the asset or liability. Level 3 inputs are unobservable inputs for the asset or
liability reflecting significant modifications to observable related market data or BP’s assumptions about pricing by market participants.
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Significant estimate or judgement
In some cases the fair values of derivatives are estimated using internal models due to the absence of quoted prices or other observable, market-
corroborated data. This applies to the group’s longer-term derivative contracts and certain options, and to the forward contracts entered into in 2012
to purchase shares in Rosneft, as well as to the majority of the group’s natural gas embedded contracts. The group’s embedded derivatives arise
primarily from long-term UK gas contracts that use pricing formulae not related to gas prices, for example, oil product and power prices. These
contracts are valued using models with inputs that include price curves for each of the different products that are built up from active market pricing
data and extrapolated to the expiry of the contracts using the maximum available external pricing information. Additionally, where limited data exists
for certain products, prices are interpolated using historic and long-term pricing relationships. Price volatility is also an input for the models.
Changes in the key assumptions could have a material impact on the fair value gains and losses on derivatives and embedded derivatives recognized
in the income statement. For more information see Note 26.
Offsetting of financial assets and liabilities
Financial assets and liabilities are presented gross in the balance sheet unless both of the following criteria are met: the group currently has a legally
enforceable right to set off the recognized amounts; and the group intends to either settle on a net basis or realize the asset and settle the liability
simultaneously. If both of the criteria are met, the amounts are set off and presented net.
Provisions, contingencies and reimbursement assets
Provisions are recognized when the group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of
resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
Where appropriate, the future cash flow estimates are adjusted to reflect risks specific to the liability.
If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax risk-free rate
that reflects current market assessments of the time value of money. Where discounting is used, the increase in the provision due to the passage of
time is recognized within finance costs. Provisions are split between amounts expected to be settled within 12 months of the balance sheet date
(current) and amounts expected to be settled later (non-current). Contingent liabilities are possible obligations whose existence will only be confirmed
by future events not wholly within the control of the group, or present obligations where it is not probable that an outflow of resources will be required
or the amount of the obligation cannot be measured with sufficient reliability.
Contingent liabilities are not recognized in the financial statements but are disclosed unless the possibility of an outflow of economic resources is
considered remote.
Where the group makes contributions into a separately administered fund for restoration, environmental or other obligations, which it does not control,
and the group’s right to the assets in the fund is restricted, the obligation to contribute to the fund is recognized as a liability where it is probable that
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such additional contributions will be made. The group recognizes a reimbursement asset separately, being the lower of the amount of the associated
restoration, environmental or other provision and the group’s share of the fair value of the net assets of the fund available to contributors.
Significant estimate or judgement
Detailed information on the Gulf of Mexico oil spill, including the financial impacts, is provided in Note 2.
The provision recognized is the best reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period,
however there are future expenditures for which it is not possible to measure the obligation reliably. These are not provided for and are disclosed as
contingent liabilities. Accounting judgement is required to identify when a provision can be measured reliably, which can be especially challenging
when complex litigation activities are ongoing.
In addition, for those provisions which are recognized, there is significant estimation uncertainty about the amounts that will ultimately be paid,
especially with regard to amounts payable under the Deepwater Horizon Court Supervised Settlement Program (DHCSSP). A provision is made for
these costs when the amount can be measured reliably; this requires an analysis of claims received and processed and consideration of the status
of ongoing legal activity.
The provision for penalties under the US Clean Water Act is based on the estimated civil penalty for strict liability. This provision is calculated based
on estimates as to the volume of oil spilled, as well as the assumption that BP did not act with gross negligence or engage in wilful misconduct,
each of which will eventually be determined by the court on the basis of the trial proceedings.
Decommissioning
Liabilities for decommissioning costs are recognized when the group has an obligation to plug and abandon a well, dismantle and remove a facility or
an item of plant and to restore the site on which it is located, and when a reliable estimate of that liability can be made. Where an obligation exists for a
new facility or item of plant, such as oil and natural gas production or transportation facilities, this liability will be recognized on construction or
installation. Similarly, where an obligation exists for a well, this liability is recognized when it is drilled. An obligation for decommissioning may also
crystallize during the period of operation of a well, facility or item of plant through a change in legislation or through a decision to terminate operations;
an obligation may also arise in cases where an asset has been sold but the subsequent owner is no longer able to fulfil its decommissioning
obligations, for example due to bankruptcy. The amount recognized is the present value of the estimated future expenditure determined in accordance
with local conditions and requirements.
A corresponding intangible asset (in the case of an exploration or appraisal well) or item of property, plant and equipment of an amount equivalent to
the provision is also recognized. The item of property, plant and equipment is subsequently depreciated as part of the asset.
Other than the unwinding of discount on the provision, any change in the present value of the estimated expenditure is reflected as an adjustment to
the provision and the corresponding asset. Such changes include foreign exchange gains and losses arising on the retranslation of the liability into the
functional currency of the reporting entity, when it is known that the liability will be settled in a foreign currency.
Environmental expenditures and liabilities
Environmental expenditures that relate to future revenues are capitalized. Expenditures that relate to an existing condition caused by past operations
that do not contribute to future earnings are expensed.
Liabilities for environmental costs are recognized when a clean-up is probable and the associated costs can be reliably estimated. Generally, the timing
of recognition 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.
Significant estimate or judgement
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 decommissioning obligations facing BP relate to the plugging and abandonment of wells and the removal and disposal of oil and natural
gas platforms and pipelines around the world. Most of these decommissioning events are many years in the future and the precise requirements
that will have to be met when the removal event actually occurs are uncertain. Decommissioning technologies and costs are constantly changing, as
well as political, environmental, safety and public expectations. If oil and natural gas production facilities and pipelines are sold to third parties and
the subsequent owner is unable to meet their decommissioning obligations, judgement must be used to determine whether BP is then responsible
for decommissioning, and if so the extent of that responsibility. Consequently, the timing and amounts of future cash flows are subject to significant
uncertainty. Any changes in the expected future costs are reflected in both the provision and the asset.
Decommissioning provisions associated with downstream and petrochemicals facilities are generally not recognized, as such potential obligations
cannot be measured, given their indeterminate settlement dates. The group performs periodic reviews of its downstream and petrochemicals long-
lived assets for any changes in facts and circumstances that might require the recognition of a decommissioning provision.
The provision for environmental liabilities is estimated based on current legal and constructive requirements, technology, price levels and expected
plans for remediation. Actual costs and cash outflows can differ from estimates because of changes in laws and regulations, public expectations,
prices, discovery and analysis of site conditions and changes in clean-up technology.
Other provisions and liabilities are recognized in the period when it becomes probable that there will be a future outflow of funds resulting from past
operations or events and the amount of cash outflow can be reliably estimated. The timing of recognition and quantification of the liability require the
application of judgement to existing facts and circumstances, which can be subject to change. Since the actual cash outflows can take place many
years in the future, the carrying amounts of provisions and liabilities are reviewed regularly and adjusted to take account of changing facts and
circumstances.
The timing and amount of future expenditures are reviewed annually, together with the interest rate used in discounting the cash flows. The interest
rate used to determine the balance sheet obligation at the end of 2013 was a real rate of 1.0% (2012 0.5%), which was based on long-dated
government bonds.
Provisions and contingent liabilities in relation to the Gulf of Mexico oil spill are discussed in Note 2. Information about the group’s other provisions is
provided in Note 29. As further described in Note 35, the group is subject to claims and actions. The facts and circumstances relating to particular
cases are evaluated regularly in determining whether it is probable that there will be a future outflow of funds and, once established, whether a
provision relating to a specific litigation should be established or revised. Accordingly, significant management judgement relating to provisions and
contingent liabilities is required, since the outcome of litigation is difficult to predict.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
Employee benefits
Wages, salaries, bonuses, social security contributions, paid annual leave and sick leave are accrued in the period in which the associated services are
rendered by employees of the group. Deferred bonus arrangements that have a vesting date more than 12 months after the period end are valued on
an actuarial basis using the projected unit credit method and amortized on a straight-line basis over the service period until the award vests. The
accounting policies for share-based payments and for pensions and other post-retirement benefits are described below.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees is measured by reference to the fair value at the date at which equity instruments are granted
and is recognized as an expense over the vesting period, which ends on the date on which the employees become fully entitled to the award. Fair
value is determined by using an appropriate valuation model. In valuing equity-settled transactions, no account is taken of any vesting conditions, other
than conditions linked to the price of the shares of the company (market conditions). Non-vesting conditions, such as the condition that employees
contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to meet a non-vesting condition, where this is within
the control of the employee is treated as a cancellation and expensed.
Cash-settled transactions
The cost of cash-settled transactions is measured at fair value at each balance sheet date and recognized as an expense over the vesting period, with a
corresponding liability for the cumulative expense recognized on the balance sheet.
Pensions and other post-retirement benefits
The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit credit method, which
attributes entitlement to benefits to the current period (to determine current service cost) and to the current and prior periods (to determine the present
value of the defined benefit obligation). Past service costs, resulting from either a plan amendment or a curtailment (a reduction in future obligations as
a result of a material reduction in the plan membership), are recognized immediately when the company becomes committed to a change.
Net interest expense relating to pensions and other post-retirement benefits represents the net change in present value of plan obligations and the
value of plan assets resulting from the passage of time, and is determined by applying the discount rate to the present value of the benefit obligation at
the start of the year, and to the fair value of plan assets at the start of the year, taking into account expected changes in the obligation or plan assets
during the year. Net interest expense relating to pensions and other post-retirement benefits is recognized in the income statement.
Remeasurements of the net defined benefit liability or asset, comprising actuarial gains and losses, and the return on plan assets (excluding amounts
included in net interest described above) are recognized within other comprehensive income in the period in which they occur.
The defined benefit pension plan surplus or deficit in the balance sheet comprises the total for each plan of the present value of the defined benefit
obligation (using a discount rate based on high quality corporate bonds), less the fair value of plan assets out of which the obligations are to be settled
directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price.
Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.
Significant estimate or judgement
Accounting for pensions and other post-retirement benefits involves judgement about uncertain events, including estimated retirement dates, salary
levels at retirement, mortality rates, determination of discount rates for measuring plan obligations and net interest expense, assumptions for inflation
rates, US healthcare cost trend rates and rates of utilization of healthcare services by US retirees.
These assumptions are based on the environment in each country. The assumptions used may vary from year to year, which would affect future net
income and net assets. Any differences between these assumptions and the actual outcome also affect future net income and net assets.
Pension and other post-retirement benefit assumptions are reviewed by management at the end of each year. These assumptions are used to
determine the projected benefit obligation at the year end and hence the surpluses and deficits recorded on the group’s balance sheet, and pension
and other post-retirement benefit expense for the following year. In 2013, we adopted the revised version of IAS 19 ‘Employee Benefits’ (see below
for further information), and we now apply the same rate of return on plan assets as we use to discount our pension liabilities. The impact of this
change on key financial statement line items is shown at the end of this note.
The pension and other post-retirement benefit assumptions at 31 December 2013, 2012 and 2011 are provided in Note 30.
The discount rate, inflation rate and the US healthcare cost trend rate have a significant effect on the amounts reported. A sensitivity analysis of the
impact of changes in these assumptions on the benefit expense and obligation is provided in Note 30.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best practice
in the countries in which we provide pensions and have been chosen with regard to the latest available published tables adjusted where appropriate
to reflect the experience of the group and an extrapolation of past longevity improvements into the future. A sensitivity analysis of the impact of
changes in the mortality assumptions on the benefit expense and obligation is provided in Note 30.
Income taxes
Income tax expense represents the sum of current tax and deferred tax. Interest and penalties relating to income tax are also included in the income
tax expense.
Income tax is recognized in the income statement, except to the extent that it relates to items recognized in other comprehensive income or directly in
equity, in which case the related tax is recognized in other comprehensive income or directly in equity.
Current tax is based on the taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it is
determined in accordance with the rules established by the applicable taxation authorities. It therefore excludes items of income or expense that are
taxable or deductible in other periods as well as items that are never taxable or deductible. The group’s liability for current tax is calculated using tax
rates and laws that have been enacted or substantively enacted by the balance sheet date.
Deferred tax is provided, using the liability method, on all temporary differences at the balance sheet date between the tax bases of assets and
liabilities and their carrying amounts for financial reporting purposes.
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135
1. Significant accounting policies, judgements, estimates and assumptions – continued
Deferred tax liabilities are recognized for all taxable temporary differences except:
• Where the deferred tax liability arises on the initial recognition of goodwill; or
• Where the deferred tax liability arises on the initial recognition of an asset or liability in a transaction that is not a business combination and, at the
time of the transaction, affects neither accounting profit nor taxable profit or loss; or
• In respect of taxable temporary differences associated with investments in subsidiaries, joint ventures and associates, where the group is able to
control the timing of the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable
future.
Deferred tax assets are recognized for all deductible temporary differences, carry-forward of unused tax credits and unused tax losses, to the extent
that it is probable that taxable profit will be available against which the deductible temporary differences and the carry-forward of unused tax credits
and unused tax losses can be utilized:
• Except where the deferred tax asset relating to the deductible temporary difference arises from the initial recognition of an asset or liability in a
transaction that is not a business combination and, at the time of the transaction, affects neither accounting profit nor taxable profit or loss.
• In respect of deductible temporary differences associated with investments in subsidiaries, joint ventures and associates, deferred tax assets are
recognized only to the extent that it is probable that the temporary differences will reverse in the foreseeable future and taxable profit will be
available against which the temporary differences can be utilized.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient
taxable profit will be available to allow all or part of the deferred tax asset to be utilized.
Deferred tax assets and liabilities are measured at the tax rates that are expected to apply in the period when the asset is realized or the liability is
settled, based on tax rates (and tax laws) that have been enacted or substantively enacted at the balance sheet date. Deferred tax assets and liabilities
are not discounted.
Deferred tax assets and liabilities are offset only when there is a legally enforceable right to set off current tax assets against current tax liabilities and
when the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different
taxable entities where there is an intention to settle the current tax assets and liabilities on a net basis or to realize the assets and settle the liabilities
simultaneously.
Significant estimate or judgement
The computation of the group’s income tax expense and liability involves the interpretation of applicable tax laws and regulations in many
jurisdictions throughout the world. The resolution of tax positions taken by the group, through negotiations with relevant tax authorities or through
litigation, can take several years to complete and in some cases it is difficult to predict the ultimate outcome. Therefore, judgement is required to
determine provisions for income taxes.
In addition, the group has carry-forward tax losses and tax credits in certain taxing jurisdictions that are available to offset against future taxable
profit. However, deferred tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused
tax losses or tax credits can be utilized. Management judgement is exercised in assessing whether this is the case.
To the extent that actual outcomes differ from management’s estimates, income tax charges or credits, and changes in current and deferred tax
assets or liabilities, may arise in future periods. For more information see Note 35.
Judgement is also required when determining whether a particular tax is an income tax or another type of tax (for example a production tax).
Accounting for deferred tax is applied to income taxes as described above, but is not applied to other types of taxes; rather such taxes are
recognized in the income statement on an appropriate basis.
Customs duties and sales taxes
Customs duties and sales taxes which are passed on to customers are excluded from revenues and expenses. Assets and liabilities are recognized net
of the amount of customs duties or sales tax except:
• Where the customs duty or sales tax incurred on a purchase of goods and services is not recoverable from the taxation authority, in which case the
customs duty or sales tax is recognized as part of the cost of acquisition of the asset.
• Receivables and payables are stated with the amount of customs duty or sales tax included.
The net amount of sales tax recoverable from, or payable to, the taxation authority is included within receivables or payables in the balance sheet.
Own equity instruments
The group’s holdings in its own equity instruments, including ordinary shares held by Employee Share Ownership Plans (ESOPs), are classified as
‘treasury shares’, or ‘own shares’ for the ESOPs, and are shown as deductions from shareholders’ equity at cost. Consideration received for the sale of
such shares is also recognized in equity, with any difference between the proceeds from sale and the original cost being taken to the profit and loss
account reserve. No gain or loss is recognized in the income statement on the purchase, sale, issue or cancellation of equity shares. Shares
repurchased under the share buy-back programme which are immediately cancelled are not shown as treasury shares or own shares, but are shown as
a deduction from the profit and loss reserve in the group statement of changes in equity.
Revenue
Revenue arising from the sale of goods is recognized when the significant risks and rewards of ownership have passed to the buyer, which is typically
at the point that title passes, and the revenue can be reliably measured.
Revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for goods provided in the normal
course of business, net of discounts, customs duties and sales taxes.
Physical exchanges are reported net, as are sales and purchases made with a common counterparty, as part of an arrangement similar to a physical
exchange. Similarly, where the group acts as agent on behalf of a third party to procure or market energy commodities, any associated fee income is
recognized but no purchase or sale is recorded. Additionally, where forward sale and purchase contracts for oil, natural gas or power have been
determined to be for trading purposes, the associated sales and purchases are reported net within sales and other operating revenues whether or not
physical delivery has occurred.
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BP Annual Report and Form 20-F 2013
1. Significant accounting policies, judgements, estimates and assumptions – continued
Generally, revenues from the production of oil and natural gas properties in which the group has an interest with joint operation partners 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.
Interest income is recognized as the interest accrues (using the effective interest rate that is the rate that exactly discounts estimated future cash
receipts through the expected life of the financial instrument to the net carrying amount of the financial asset).
Dividend income from investments is recognized when the shareholders’ right to receive the payment is established.
Research
Research costs are expensed as incurred.
Finance costs
Finance costs directly attributable to the acquisition, construction or production of qualifying assets, which are assets that necessarily take a substantial
period of time to get ready for their intended use, are added to the cost of those assets until such time as the assets are substantially ready for their
intended use. All other finance costs are recognized in the income statement in the period in which they are incurred.
Impact of new International Financial Reporting Standards
Adopted for 2013
BP adopted several new and amended standards issued by the IASB with effect from 1 January 2013. Of these the following two standards have a
significant effect on the group’s consolidated financial statements:
IFRS 11 ‘Joint Arrangements’
In May 2011, the IASB issued IFRS 11 ‘Joint Arrangements’, one of a suite of standards relating to interests in other entities and related disclosures.
IFRS 11 establishes a principle that applies to the accounting for all joint arrangements, whereby parties to the arrangement account for their
underlying contractual rights and obligations relating to the joint arrangement. IFRS 11 identifies two types of joint arrangements. A ‘joint venture’ is a
joint arrangement whereby the parties that have joint control of the arrangement have rights to the net assets of the arrangement. A ‘joint operation’ is
a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to
the arrangement. Investments in joint ventures are accounted for using the equity method. Investments in joint operations are accounted for by
recognizing the group’s assets, liabilities, revenue and expenses relating to the joint operation.
The main impact of IFRS 11 is that certain of the group’s former jointly controlled entities, which were equity accounted, now fall under the definition
of a joint operation under IFRS 11. Whilst the effect of the new requirements on the group’s reported income and net assets is not material, the
change does impact certain of the component lines of the group’s financial statements, as shown in the table below. We have derecognized
approximately $7 billion of investments and we now recognize the group’s assets, liabilities, revenue and expenses relating to these arrangements.
BP’s share of oil and natural gas reserves associated with former jointly controlled entities that were previously equity-accounted, and are now
classified as joint operations, have been reclassified from ‘equity-accounted entities’ to ‘subsidiaries’ in the Supplementary information on oil and
natural gas.
Amendments to IAS 19 ‘Employee Benefits’
In June 2011, the IASB issued an amended version of IAS 19 ‘Employee Benefits’, which brings in various changes relating to the recognition and
measurement of post-retirement defined benefit expense and termination benefits, and to the disclosures for all employee benefits. The main impact
for BP is that the expense for defined benefit pension and other post-retirement benefit plans now includes a net interest income or expense, which is
calculated by taking the discount rate used for measuring the obligation and applying that to the net defined benefit asset or liability. This means that
the expected return on assets credited to profit or loss (previously calculated based on the expected long-term return on pension assets) is now based
on a lower corporate bond rate, the same rate that is used to discount the pension liability. The impact was to decrease profit before tax by $1,001
million for the year ended 31 December 2013 (2012 $763 million, 2011 $659 million) with other comprehensive income being increased by the same
amount. There was no impact on the balance sheet at 31 December or on cash flows.
Adjustments made to certain selected financial statement line items
The following table sets out the adjustments made to certain selected financial statement line items of the previously reported comparative amounts
as a result of the adoption of the amended IAS 19 ‘Employee Benefits’ and the new standard IFRS 11 ‘Joint Arrangements’.
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Selected lines only
Income statement
Earnings from joint ventures – after interest and tax
Net finance income (expense) relating to pensions and
other post-retirement benefits
Profit for the year
Earnings per share – cents
Profit for the year attributable to BP shareholders
Basic
Diluted
Balance sheet
Property, plant and equipment
Intangible assets
Investments in joint ventures
Net assets
Cash flow statement
Profit (loss) before taxation
Net cash provided by operating activities
Net cash used in investing activities
Increase (decrease) in cash and cash equivalents
a Balance sheet amounts presented are as at 1 January 2012.
As reported
IFRS 11
IAS 19
2012
As restated
As reported
IFRS 11
IAS 19
2011
As restateda
$ million (except per share amounts)
744
(484)
–
260
1,304
(537)
–
767
201
11,816
(4)
22
(763)
(587)
(566)
11,251
263
26,097
(4)
2
(659)
(490)
(400)
25,609
60.86
60.45
0.12
0.11
(3.09)
(3.06)
57.89
57.50
135.93
134.29
0.01
0.01
(2.59)
(2.56)
133.35
131.74
120,448
24,041
15,724
119,620
4,883
591
(7,110)
132
–
–
–
–
18,809
20,397
(12,962)
5,481
85
82
(113)
(23)
(763)
–
–
–
125,331
24,632
8,614
119,752
18,131
20,479
(13,075)
5,458
119,214
21,102
15,518
112,482
4,217
551
(7,215)
103
–
–
–
–
38,834
22,154
(26,633)
(4,489)
53
64
(120)
(62)
(659)
–
–
–
123,431
21,653
8,303
112,585
38,228
22,218
(26,753)
(4,551)
BP Annual Report and Form 20-F 2013
137
1. Significant accounting policies, judgements, estimates and assumptions – continued
Detailed restated financial information for 2012 and 2011 is shown in BP Financial and Operating Information 2008-2012 available on bp.com/investors.
Other standards
A number of other new or amended standards have been adopted by the group with effect from 1 January 2013 but do not have a significant impact
on the financial statements. These include:
IFRS 10 ‘Consolidated Financial Statements’ introduces a single consolidation model that identifies control as the basis for consolidation. The new
model applies to all types of entities, including structured entities. Under the new model, an investor controls an investee when it is exposed, or has
rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee. There
was no effect on the group’s reported income or net assets as a result of the adoption of IFRS 10.
IFRS 12 ‘Disclosures of Interests in Other Entities’ combines all the disclosure requirements for an entity’s interests in subsidiaries, joint arrangements,
associates and structured entities into one comprehensive disclosure standard. There was no effect on the group’s reported income or net assets as a
result of the adoption of IFRS 12. The disclosures required by the standard are included in this report.
In May 2011, the IASB issued a new standard, IFRS 13 ‘Fair Value Measurement’. The new standard defines fair value, sets out a framework for
measuring fair value and contains the required disclosures about fair value measurements. IFRS 13 does not require fair value measurements in
addition to those already required or permitted by other standards, rather it prescribes how fair value should be measured if another standard requires
it. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date i.e. it is an exit price. There was no significant impact on the group’s reported income or net assets as a result of
the adoption of IFRS 13. The disclosures required by the new standard are included in this report.
In December 2011, the IASB issued an amendment to IFRS 7 ‘Disclosures – Offsetting Financial Assets and Financial Liabilities’. This amendment
introduces new disclosure requirements about the effects of offsetting financial assets and financial liabilities and related arrangements on an entity’s
balance sheet. The new disclosures are included in this report.
In June 2011, the IASB issued amendments to IAS 1 ‘Presentation of Financial Statements’ on the presentation of other comprehensive income (OCI).
The amendments require that those items of OCI that might be reclassified to profit or loss at a future date be presented separately from those items
that will never be reclassified to profit or loss. The adoption of the amended standard has a presentational impact on the group’s statement of
comprehensive income, with no effect on the reported income, total comprehensive income, or net assets of the group. The presentation required by
the amended standard is included in this report.
In May 2013, the IASB issued an amendment to IAS 36 ‘Impairment of Assets’ in relation to the disclosure of recoverable amounts for non-financial
assets. The amendment addressed certain unintended consequences arising from consequential amendments made to IAS 36 when IFRS 13 was
issued. Although the mandatory effective date for application of the amendment is for annual periods beginning on or after 1 January 2014, the group
has early-adopted it in these financial statements.
In addition, a number of other standards and interpretations were adopted in the year which had no significant impact on the group’s reported income
and net assets.
Not yet adopted
The following pronouncements from the IASB will become effective for future financial reporting periods and have not yet been adopted by the group.
As part of the IASB’s project to replace IAS 39 ‘Financial Instruments: Recognition and Measurement’, in November 2009 the IASB issued the first
phase of IFRS 9 ‘Financial Instruments’, dealing with the classification and measurement of financial assets. In October 2010, the IASB updated IFRS 9
by incorporating the requirements for the accounting for financial liabilities and in November 2013 the IASB published revised guidance for hedge
accounting. The remaining phase of IFRS 9, dealing with impairment, and further changes to the classification and measurement requirements, are still
to be completed. In November 2013, the IASB also removed the effective date from IFRS 9 and will decide on an effective date when the entire IFRS 9
project is closer to completion. BP has not yet decided the date of adoption for the group and has not yet completed its evaluation of the effect of
adoption. The EU has not yet adopted IFRS 9.
In December 2011, the IASB issued an amendment to IAS 32 ‘Offsetting Financial Assets and Financial Liabilities’. This amendment clarifies the
presentation requirements in relation to offsetting financial assets and financial liabilities on an entity’s balance sheet. The amendment to IAS 32 is
effective for annual periods beginning on or after 1 January 2014. BP’s evaluation of the effect of adoption of the amendment to IAS 32 is substantially
complete, and is not expected to result in any significant changes to the offsetting of financial assets and liabilities on the group’s balance sheet.
There are no other standards and interpretations in issue but not yet adopted that the directors anticipate will have a material effect on the reported
income or net assets of the group.
138
BP Annual Report and Form 20-F 2013
2. Significant event – Gulf of Mexico oil spill
As a consequence of the Gulf of Mexico oil spill in April 2010, BP continues to incur costs and has also recognized liabilities for certain future costs.
Liabilities of uncertain timing or amount, for which no provision has been made, have been disclosed as contingent liabilities.
The cumulative pre-tax income statement charge since the incident amounts to $42.7 billion. For more information on the types of expenditure
included in the cumulative income statement charge, see Impact upon the group income statement below. The cumulative income statement charge
does not include amounts for obligations that BP considers are not possible, at this time, to measure reliably. For further information, including
developments in relation to the interpretation of business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement, see
Provisions and contingent liabilities below.
The total amounts that will ultimately be paid by BP in relation to all the obligations relating to the incident are subject to significant uncertainty and the
ultimate exposure and cost to BP will be dependent on many factors, as discussed under Provisions and contingent liabilities below, including in
relation to any new information or future developments. These could have a material impact on our consolidated financial position, results of operations
and cash flows. The risks associated with the incident could also heighten the impact of the other risks to which the group is exposed as further
described under Risk factors on page 51 and Legal proceedings on page 257.
The impacts of the Gulf of Mexico oil spill on the income statement, balance sheet and cash flow statement of the group are included within the
relevant line items in those statements and are shown in the table below.
Income statement
Production and manufacturing expenses
Profit (loss) before interest and taxation
Finance costs
Profit (loss) before taxation
Less: Taxation
Profit (loss) for the period
Balance sheet
Current assets
Trade and other receivables
Current liabilities
Trade and other payables
Provisions
Net current assets (liabilities)
Non-current assets
Other receivables
Non-current liabilities
Other payables
Provisions
Deferred tax
Net non-current assets (liabilities)
Net assets (liabilities)
Cash flow statement
Profit (loss) before taxation
Finance costs
Net charge for provisions, less payments
(Increase) decrease in other current and non-current assets
Increase (decrease) in other current and non-current liabilities
Pre-tax cash flows
2013
Of which:
amount related
to the trust
fund
(1,542)
1,542
–
1,542
–
1,542
Total
430
(430)
39
(469)
73
(396)
Total
4,995
(4,995)
19
(5,014)
94
(4,920)
2,457
2,457
4,239
(1,030)
(2,951)
(1,524)
(1)
–
2,456
(522)
(5,449)
(1,732)
2,442
2,442
2,264
(2,986)
(6,395)
2,748
(4,191)
(5,715)
(469)
39
1,129
(1,481)
(618)
(1,400)
–
–
–
2,442
4,898
1,542
–
–
(1,542)
–
–
(175)
(9,751)
4,002
(3,660)
(5,392)
(5,014)
19
4,834
(998)
(5,090)
(6,249)
2012
Of which:
amount related
to the trust
fund
(1,191)
1,191
12
1,179
–
1,179
4,178
(22)
–
4,156
2,264
–
–
–
2,264
6,420
1,179
12
–
(1,191)
(4,860)
(4,860)
$ million
2011
Of which:
amount related
to the trust
fund
(3,995)
3,995
52
3,943
–
3,943
Total
(3,800)
3,800
58
3,742
(1,387)
2,355
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3,742
58
2,699
(4,292)
(11,113)
(8,906)
3,943
52
–
(4,038)
(10,097)
(10,140)
The impact on net cash provided by operating activities, on a post-tax basis, amounted to an outflow of $73 million (2012 outflow of $2,382 million and
2011 outflow of $6,813 million).
Trust fund
BP established the Deepwater Horizon Oil Spill Trust (the Trust) in 2010, to be funded in the amount of $20 billion, to satisfy legitimate individual and
business claims, state and local government claims resolved by BP, final judgments and settlements, state and local response costs, and natural
resource damages and related costs. The Trust is available to fund the qualified settlement funds (QSFs) established under the terms of the settlement
agreements (comprising the Economic and Property Damages (EPD) Settlement Agreement and the Medical Benefits Class Action Settlement) with
the PSC administered through the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), and the separate BP claims programme – see
Provisions and contingent liabilities below for further information. Fines and penalties are not covered by the trust fund.
The funding of the Trust was completed in the fourth quarter of 2012. The obligation to fund the $20-billion trust fund, adjusted to take account of the
time value of money, was recognized in full in 2010 and charged to the income statement.
BP’s rights and obligations in relation to the $20-billion trust fund are accounted for in accordance with IFRIC 5 ‘Rights to Interests Arising from
Decommissioning, Restoration and Environmental Rehabilitation Funds’. An asset has been recognized representing BP’s right to receive
reimbursement from the trust fund. This is the portion of the estimated future expenditure provided for that will be settled by payments from the trust
fund. We use the term ‘reimbursement asset’ to describe this asset. BP will not actually receive any reimbursements from the trust fund, instead
payments will be made directly from the trust fund, and BP will be released from its corresponding obligation. The reimbursement asset is recorded
within other receivables on the balance sheet apportioned between current and non-current elements. The table below shows movements in the
BP Annual Report and Form 20-F 2013
139
2. Significant event – Gulf of Mexico oil spill – continued
reimbursement asset during the period to 31 December 2013. The net increase in the provision of $1,542 million for the full year relates principally to
business economic loss claims processed by the DHCSSP subsequent to finalization of the BP Annual Report and Form 20-F 2012 that have been paid
as well as increases in the provision for claims administration costs. The amount of the reimbursement asset at 31 December 2013 is equal to the
amount of provisions and payables recognized at that date that will be covered by the trust fund – see below.
At 1 January
Increase in provision for items covered by the trust fund
Derecognition of provision for items that cannot be reliably estimated
Amounts paid directly by the trust fund
At 31 December
Of which – current
– non-current
2013
6,442
1,921
(379)
(3,085)
4,899
2,457
2,442
2012
9,875
1,985
(794)
(4,624)
6,442
4,178
2,264
$ million
Cumulative since the
incident
–
20,511
(1,173)
(14,439)
4,899
2,457
2,442
Any increases in estimated future expenditure that will be covered by the trust fund (up to an aggregate of $20 billion) have no net income statement
effect as a reimbursement asset is also recognized, as described above. As at 31 December 2013, the cumulative charges, and the associated
reimbursement asset recognized, amounted to $19,338 million. Thus, a further $662 million could be charged in subsequent periods for items covered
by the trust fund with no net impact on the income statement. Additional liabilities in excess of this amount regarding claims under the Oil Pollution Act
of 1990 (OPA 90), claims that are currently administered by the DHCSSP, or otherwise, including the various claims described in Legal proceedings on
page 257, would be expensed to the income statement. Information on those items that currently cannot be estimated reliably is provided under
Provisions and contingent liabilities below.
Under the terms of the EPD Settlement Agreement with the PSC, several QSFs were established in 2012. These QSFs each relate to specific
elements of the agreement, have been and will continue to be funded through payments from the Trust, and are available to make payments to
claimants in accordance with those elements of the agreement.
As at 31 December 2013, the aggregate cash balances in the Trust and the QSFs amounted to $6.7 billion, including $1.2 billion remaining in the
seafood compensation fund which has yet to be distributed and $0.9 billion held for natural resource damage early restoration. Should the cash
balances in the trust fund not be sufficient, payments in respect of legitimate claims and other costs will be made directly by BP.
The EPD Settlement Agreement with the PSC provides for a court-supervised settlement programme which commenced operation on 4 June 2012.
See Provisions below for further information on the current status of the EPD Settlement Agreement. In addition, a separate BP claims programme
began processing claims from claimants not in the Economic and Property Damages class as determined by the EPD Settlement Agreement or who
have requested to opt out of that settlement. Payments made to claimants through the BP claims programme are paid directly from the Trust. A
separate claims administrator has been appointed to pay medical claims and to implement other aspects of the Medical Benefits Class Action
Settlement. For further information on the PSC settlements, see Legal proceedings on page 257.
Other payables
BP reached an agreement with the US government in 2012, which was approved by the court in 2013, to resolve all federal criminal claims arising from
the incident. Under the agreement, BP will pay $4 billion over a period of five years. At 31 December 2013, the remaining payable was $3,525 million,
of which $565 million falls due in 2014.
BP also reached a settlement with the US Securities and Exchange Commission (SEC) in 2012, resolving the SEC’s Gulf of Mexico oil spill-related civil
claims. As part of the settlement, BP agreed to a civil penalty of $525 million. At 31 December 2013 the remaining payable, due in 2014, was
$175 million plus accrued interest.
The amounts described above were reclassified from provisions to other payables upon court approval of the agreement with the US government and
settlement with the SEC.
Provisions and contingent liabilities
Provisions
BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure, spill response costs, litigation and claims,
and Clean Water Act penalties that can be measured reliably at this time.
Movements in each class of provision during the year and cumulatively since the incident are presented in the tables below.
At 1 January
Increase (decrease) in provision – items not covered by the trust fund
– items covered by the trust fund
Derecognition of provision for items that cannot be reliably estimateda
Reclassification of amounts between categories of provision
Unwinding of discount
Change in discount rate
Reclassified to other payables – items covered by the trust fund
– items not covered by the trust fund
Utilization – paid by BP
– paid by the trust fund
At 31 December
Of which – current
– non-current
Of which – payable from the trust fund
a Relates to items covered by the trust fund.
140
BP Annual Report and Form 20-F 2013
Environmental
1,862
(24)
24
–
47
1
(5)
–
–
(60)
(255)
1,590
389
1,201
1,253
Spill
response
345
(66)
–
–
(47)
–
–
–
–
(143)
–
89
84
5
–
Litigation
and claims
9,483
408
1,897
(379)
–
–
–
(84)
(3,849)
(523)
(2,796)
4,157
2,478
1,679
3,595
Clean Water
Act
3,510
–
–
–
–
–
–
–
–
–
–
3,510
–
3,510
–
$ million
2013
Total
15,200
318
1,921
(379)
–
1
(5)
(84)
(3,849)
(726)
(3,051)
9,346
2,951
6,395
4,848
2. Significant event – Gulf of Mexico oil spill – continued
Increase in provision – items not covered by the trust fund
– items covered by the trust fund
Derecognition of provision for items that cannot be reliably estimateda
Reclassification of amounts between categories of provision
Unwinding of discount
Change in discount rate
Reclassified to other payables – items covered by the trust fund
– items not covered by the trust fund
Utilization – paid by BP
– paid by the trust fund
At 31 December 2013
a Relates to items covered by the trust fund.
$ million
Cumulative since the incident
Environmental
Spill
response
Litigation
and claims
Clean Water
Act
544
2,353
–
47
12
17
–
–
(237)
(1,146)
1,590
11,456
56
–
(47)
–
–
–
–
(11,367)
(9)
8,529
18,102
(1,173)
–
6
–
(84)
(4,199)
(3,773)
(13,251)
89
4,157
3,510
–
–
–
–
–
–
–
–
–
3,510
Total
24,039
20,511
(1,173)
–
18
17
(84)
(4,199)
(15,377)
(14,406)
9,346
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Environmental
The environmental provision includes $320 million for BP’s commitment to fund the Gulf of Mexico Research Initiative, which is a 10-year research
programme to study the impact of the incident on the marine and shoreline environment of the Gulf of Mexico. In addition, BP faces claims under the Oil
Pollution Act of 1990 (OPA 90) for natural resource damages. These damages include, among other things, the reasonable costs of assessing the injury to
natural resources. During 2011, BP entered a framework agreement with natural resource trustees for the United States and five Gulf-coast states, providing
for up to $1 billion to be spent on early restoration projects to address natural resource injuries resulting from the oil spill, to be funded from the $20-billion
trust fund. In 2012, work began on the initial set of early restoration projects identified under this framework. At 31 December 2013 the amount provided for
natural resource damage assessment costs and early restoration projects was $1,224 million. Until the size, location and duration of the impact is assessed, it
is not possible to estimate reliably either the amounts or timing of the remaining natural resource damages claims other than the assessment and early
restoration costs noted above, therefore no additional amounts have been provided for these items and they are disclosed as a contingent liability.
Spill response
The spill response provision relates primarily to ongoing shoreline operational activity.
Litigation and claims
The litigation and claims provision includes amounts that can be estimated reliably for the future cost of settling claims by individuals and businesses
for damage to real or personal property, lost profits or impairment of earning capacity and loss of subsistence use of natural resources (‘Individual and
Business Claims’), and claims by state and local government entities for removal costs, damage to real or personal property, loss of government
revenue and increased public services costs (‘State and Local Claims’), under OPA 90 and other legislation, except as described under Contingent
liabilities below. Claims administration costs and legal costs have also been provided for. The timing of payment of litigation and claims provisions
classified as non-current is dependent on on-going legal activity and is therefore uncertain.
BP has provided for its best estimate of the cost associated with the PSC settlement agreements with the exception of the cost of business economic
loss claims. As part of its monitoring of payments made by the DHCSSP, BP identified multiple business economic loss claim determinations that
appeared to result from an interpretation of the EPD Settlement Agreement by the claims administrator that BP believes was incorrect.
Between March 2013 and March 2014, there were various rulings from both the federal District Court in New Orleans (the District Court) and a panel
of the US Court of Appeals for the Fifth Circuit (the business economic loss panel) on matters relating to the interpretation of the EPD Settlement
Agreement, in particular on the issue of matching revenue and expenses as well as causation requirements of the EPD Settlement Agreement.
As reported in BP Annual Report and Form 20-F 2012, the estimated cost of the PSC settlement for Individual and Business Claims was $7.7 billion at
31 December 2012. This estimate increased during the year to $9.6 billion to reflect all claims processed by the DHCSSP for which eligibility notices
had been issued and increases in claims administration costs. As a result of the District Court’s preliminary injunction issued on 18 October 2013 that,
amongst other things, required the claims administrator to temporarily suspend payments of business economic loss claims other than those claims
supported by sufficiently matched accrual-basis accounting or any other business economic loss claim for which the claims administrator determines
that the matching of revenue and expenses is not an issue, the provision for $0.4 billion of claims for which eligibility notices had been issued but had
not yet been paid was derecognized as BP considered and continues to consider that no reliable estimate can be made for these claims. At
31 December 2013, the total costs of the PSC settlement that BP considers can be reliably estimated is therefore $9.2 billion.
On 5 December 2013, the District Court amended its earlier preliminary injunction and temporarily suspended the issuance of final determination
notices and payments of business economic loss claims, until the business economic loss issues have been resolved. On 24 December 2013, the
District Court ruled on the issues in relation to the matching of revenue and expenses and causation that were remanded to it by the business
economic loss panel. Regarding matching, the District Court reversed its earlier decision and ruled that the claims administrator, in administering
business economic loss claims, must match revenue with the variable expenses incurred by claimants in conducting their business, even where the
revenues and expenses were recorded at different times. The District Court assigned to the claims administrator the development of more detailed
matching requirements. On 12 February 2014, the claims administrator issued a draft policy addressing the matching of revenue and expenses for
business economic loss claims. The parties have made written submissions on the draft policy and the claims administrator will issue a final policy to
which BP and the PSC have the right to object and seek review by the District Court. Regarding causation, the District Court ruled that the EPD
Settlement Agreement contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. BP appealed
the District Court’s ruling on causation to the business economic loss panel and moved for a permanent injunction that would prevent the claims
administrator from making awards to claimants whose alleged injuries are not traceable to the spill. On 3 March 2014, the business economic loss
panel affirmed the District Court’s ruling on causation and denied BP’s motion for a permanent injunction. BP is considering its appeal options,
including a potential petition that all the active judges of the Fifth Circuit review the 3 March decision. Under the terms of the business economic loss
panel’s ruling, the injunction temporarily suspending issuance of final determination notices and payments of business economic loss claims will be
lifted when the matter is transferred back to the District Court; the timing of this would be affected by the status of any such petition by BP.
BP Annual Report and Form 20-F 2013
141
2. Significant event – Gulf of Mexico oil spill – continued
In addition to the proceedings in relation to the interpretation of the EPD Settlement Agreement, following the District Court’s final order and judgment
approving the EPD Settlement in January 2013, groups of purported members of the Economic and Property Damages Settlement Class (the Appellants)
appealed from the District Court’s approval of that settlement to a different panel of the Fifth Circuit. On 10 January 2014, that other panel
of the Fifth Circuit affirmed the District Court’s approval of the EPD Settlement but left to the business economic loss panel of the Fifth Circuit the question
of how to interpret the EPD Settlement Agreement, including the meaning of the causation requirements of that agreement (see above). BP and several
Appellants have filed petitions requesting that all the active judges of the Fifth Circuit review the decision to uphold approval of the EPD Settlement.
See Legal proceedings on page 257 for further details on the settlements with the PSC and related matters.
Until the uncertainties described below are resolved, management is unable to estimate reliably the value and volume of future business economic
loss claims and whether and to what extent received or processed but unpaid business economic loss claims will be paid. Firstly, the inherent
uncertainty as to the interpretation of the EPD Settlement Agreement in respect of matching and causation issues will continue until the more detailed
matching requirements are finalized by the claims administrator and are implemented by the DHCSSP; the issue of causation and the requirements for
class membership under the EPD Settlement Agreement are resolved on appeal; and the impact of any new policies and procedures in response to
these issues on the value and volume of business economic loss claims becomes clear. Furthermore, the Fifth Circuit has yet to decide whether to
grant the petitions seeking review of its decision affirming approval of the EPD Settlement and, if granted, whether to alter its decision in that appeal.
Secondly, uncertainty arises from the lack of sufficient claims data under the DHCSSP from which to extrapolate any reliable trends – the number of
business economic loss claims received and the average amounts paid in respect of such claims prior to the District Court’s injunction were higher
than previously assumed by BP. This inability to extrapolate any reliable trends may or may not continue once the uncertainties concerning the
interpretation of the EPD Settlement Agreement described above have been resolved. Thirdly, there is uncertainty as to the ultimate deadline for filing
business economic loss claims, which is dependent on the date on which all relevant appeals are concluded. Management believes, therefore, that no
reliable estimate can currently be made of any business economic loss claims not yet received, processed and paid by the DHCSSP. A provision for
business economic loss claims will be established when a reliable estimate can be made of the liability.
The total cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.2 billion because the current estimate
does not reflect business economic loss claims not yet received, processed and paid. The DHCSSP has issued eligibility notices, disputed by BP, in
respect of business economic loss claims of $1,019 million which have not yet been paid. Furthermore, a significant number of business economic
loss claims have been received but have not yet been processed, and further claims are likely to be received.
The provision recognized for litigation and claims includes an estimate for State and Local Claims. Although the provision recognized is BP’s current reliable
best estimate of the amount required to settle these obligations, significant uncertainty exists in relation to the outcome of any litigation proceedings and
the amount of claims that will become payable by BP. See Legal proceedings on page 257 and Contingent liabilities below for further details.
Clean Water Act penalties
A charge for potential Clean Water Act Section 311 penalties was first included in BP’s second-quarter 2010 interim financial statements. At the time
that charge was taken, the latest estimate from the intra-agency Flow Rate Technical Group created by the National Incident Commander in charge of
the spill response was between 35,000 and 60,000 barrels per day. The mid-point of that range, 47,500 barrels per day, was used for the purposes of
calculating the charge. For the purposes of calculating the amount of the oil flow that was discharged into the Gulf of Mexico, the amount of oil that
had been or was projected to be captured in vessels on the surface was subtracted from the total estimated flow up until when the well was capped
on 15 July 2010. The result of this calculation was an estimate that approximately 3.2 million barrels of oil had been discharged into the Gulf. This
estimate of 3.2 million barrels was calculated using a total flow of 47,500 barrels per day multiplied by the 85 days from 22 April 2010 to 15 July 2010
less an estimate of the amount captured on the surface (approximately 850,000 barrels).
This estimated discharge volume was then multiplied by $1,100 per barrel – the maximum amount the statute allows in the absence of gross negligence or
wilful misconduct – for the purposes of estimating a potential penalty. This resulted in a provision of $3,510 million for potential penalties under Section 311.
BP intends to argue for a penalty lower than $1,100 per barrel. The actual penalty a court may impose could be lower than $1,100 per barrel if it were
determined that such a lower penalty was appropriate based on the factors a court is directed to consider in assessing a penalty. In particular, in
determining the amount of a civil penalty, Section 311 directs a court to consider a number of enumerated factors, including “the seriousness of the
violation or violations, the economic benefit to the violator, if any, resulting from the violation, the degree of culpability involved, any other penalty for
the same incident, any history of prior violations, the nature, extent, and degree of success of any efforts of the violator to minimize or mitigate the
effects of the discharge, the economic impact of the penalty on the violator, and any other matters as justice may require”. Civil penalties above
$1,100 per barrel up to a statutory maximum of $4,300 per barrel of oil discharged would only be imposed if alleged gross negligence or wilful
misconduct were proven. The $1,100 per-barrel rate has been utilized for the purposes of calculating the provision after considering and weighing all
possible outcomes and in light of: (i) the company’s conclusion that it did not act with gross negligence or engage in wilful misconduct; and (ii) the
uncertainty as to whether a court would assess a penalty below the $1,100 statutory maximum.
On 2 August 2010, the United States Department of Energy and the Flow Rate Technical Group had issued an estimate that 4.9 million barrels of oil
had flowed from the Macondo well, and 4.05 million barrels had been discharged into the Gulf (the difference being the amount of oil captured by
vessels on the surface as part of BP’s well containment efforts).
It was and remains BP’s view, based on the analysis of available data by its experts, that the 2 August 2010 Government estimate is not reliable. BP
believes that the 2 August 2010 discharge estimate is overstated by at least 20%. If the flow rate were 20% lower than the 2 August 2010 estimate,
then the amount of oil that flowed from the Macondo well would be approximately 3.9 million barrels and the amount discharged into the Gulf would
be approximately 3.1 million barrels (using a current estimate of barrels captured by vessels on the surface of 810,000 in line with the stipulation
entered with the US government – see Legal proceedings), which is not materially different from the amount we used for our original estimate at the
end of the second quarter 2010.
For the purposes of calculating a provision for fines and penalties under Section 311 of the Clean Water Act, BP has continued to use an estimate of
3.2 million barrels of oil discharged to the Gulf of Mexico and a penalty of $1,100 per barrel, as its current best estimate, as defined in paragraphs 36-40
of IAS 37 ‘Provisions, Contingent Liabilities and Contingent Assets’, of the amounts which may be used in calculating the penalty under Section 311 of
the Clean Water Act and as a result, the provision at the end of the year was $3,510 million.
The amount and timing of the amount to be paid ultimately is subject to significant uncertainty since it will depend on what is determined by the court
in the federal multi-district litigation proceedings in New Orleans (MDL 2179) as to negligence, gross negligence or wilful misconduct, the volume of oil
spilled and the application of statutory penalty factors. The trial court could issue its decision on the first two phases of the trial (which considered the
issues of negligence or gross negligence in phase one, and source control efforts and the volume of oil spilled in phase two) at any time and has not
yet scheduled a hearing on the subsequent phase regarding the application of statutory penalty factors. The court has wide discretion in its
determination as to whether a defendant’s conduct involved negligence or gross negligence as well as in its determinations on the volume of oil spilled
and the application of statutory penalty factors.
142
BP Annual Report and Form 20-F 2013
2. Significant event – Gulf of Mexico oil spill – continued
See Legal proceedings on page 257 for further details on all litigation and claims activity.
Provision movements
The total amount recognized as an increase in provisions during the year was $2,239 million, including $1,921 million for items covered by the trust
fund and $318 million for other items (2012 $6,868 million, including $1,985 million for items covered by the trust fund and $4,883 million for other
items). In addition, $379 million (2012 $794 million) was derecognized relating to items that will be covered by the trust fund but which can no longer
be reliably estimated. After deducting amounts utilized during the year totalling $3,777 million, including payments from the trust fund of $3,051 million
and payments made directly by BP of $726 million (2012 $5,864 million, including payments from the trust fund of $4,624 million and payments made
directly by BP of $1,240 million), and after reclassifications and adjustments for discounting, the remaining provision as at 31 December 2013 was
$9,346 million (2012 $15,200 million).
The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty and the
ultimate exposure and cost to BP will be dependent on many factors. Furthermore, significant uncertainty exists in relation to the amount of claims that
will become payable by BP, the amount of fines that will ultimately be levied on BP (including any determination of BP’s culpability based on any
findings of negligence, gross negligence or wilful misconduct), the outcome of litigation and arbitration proceedings, and any costs arising from any
longer-term environmental consequences of the oil spill, which will also impact upon the ultimate cost for BP. The amount and timing of any amounts
payable could also be impacted by any further settlements which may or may not occur. Although the provision recognized is the current best reliable
estimate of expenditures required to settle certain present obligations at the end of the reporting period, there are future expenditures for which it is
not possible to measure the obligation reliably.
Contingent liabilities
BP has provided for its best estimate of amounts expected to be paid from the trust fund that can be measured reliably. This includes certain amounts
expected to be paid pursuant to the Oil Pollution Act of 1990 (OPA 90). It is not possible, at this time, to measure reliably other obligations arising from
the incident that are under the terms of the trust fund, namely any obligation in relation to natural resource damages claims or associated legal costs
(except for the estimated costs of the assessment phase and costs relating to early restoration agreements under the $1-billion framework agreement
referred to above), claims asserted in civil litigation including any further litigation through excluded parties from the PSC settlement including as set
out in Legal proceedings, the cost of business economic loss claims under the PSC settlement not yet received, processed and paid by the DHCSSP,
any further obligation that may arise from state and local government submissions under OPA 90 and any obligation in relation to other potential private
or governmental litigation, nor is it practicable to estimate their magnitude or possible timing of payment. Therefore, no amounts have been provided
for these obligations as at 31 December 2013.
Natural resource damages resulting from the oil spill are currently being assessed. BP and the federal and state trustees are collecting extensive data in
order to assess the extent of damage to wildlife, shoreline, near shore and deepwater habitats, and recreational uses, among other things. The study
data will inform an assessment of injury to the Gulf Coast natural resources and the development of a restoration plan to address the identified injuries.
Detailed analysis and interpretation continue on the data that have been collected. Any early restoration projects undertaken pursuant to the $1-billion
framework agreement could mitigate the total damages resulting from the incident. Accordingly, until the size, location and duration of the impact is
assessed, it is not possible to estimate reliably either the amounts or timing of the remaining natural resource damages claims, therefore no such
amounts have been provided as at 31 December 2013.
As described under Provisions above, BP has identified multiple business economic loss claim determinations under the PSC settlement that appeared
to result from an interpretation of the EPD Settlement Agreement by the claims administrator that BP believes was incorrect. Uncertainty as to the
interpretation of the EPD Settlement Agreement will continue until the effects of the implementation of new policies and procedures are known, the
issue of causation and the requirements for class membership under the EPD Settlement Agreement are resolved on appeal and the courts have ruled
on the appeals in relation to the final order and judgment approving the EPD Settlement. Therefore the potential cost of business economic loss claims
not yet received, processed and paid is not provided for and is disclosed as a contingent liability. A significant number of business economic loss
claims have been received but have not yet been processed and paid, and further claims are likely to be received.
As described above in Provisions, a provision has been made for State and Local claims that can be measured reliably. In January 2013, the States of
Alabama, Mississippi and Florida submitted or asserted claims to BP under OPA 90 for alleged losses including economic losses and property damage
as a result of the Gulf of Mexico oil spill. BP is evaluating these claims. The States of Louisiana and Texas have also asserted similar claims. The
amounts claimed, certain of which include punitive damages or other multipliers, are very substantial. However BP considers these claims
unsubstantiated and the methodologies used to calculate these claims to be seriously flawed, not supported by OPA 90, not supported by
documentation, and to substantially overstate the claims. Similar claims have also been submitted by various local government entities and a foreign
government under OPA 90, and more claims are expected to be submitted. The amounts alleged in the submissions for these State and Local Claims
total approximately $35 billion. BP will defend vigorously against these claims if adjudicated at trial.
Proceedings relating to securities class actions (MDL 2185) pending in federal court in Texas, including a purported class action on behalf of purchasers
of American Depository Shares under US federal securities law, are continuing. A jury trial is scheduled to begin in October 2014. No reliable estimate
can be made of the amounts that may be payable in relation to these proceedings, if any, so no provision has been recognized at 31 December 2013.
In addition to the State and Local claims and securities class actions described above, BP is named as a defendant in approximately 2,950 other civil
lawsuits brought by individuals, corporations and government entities in US federal and state courts, as well as certain foreign jurisdictions, resulting
from the Deepwater Horizon accident, the Gulf of Mexico oil spill, and the spill response efforts. Further actions are likely to be brought. Among other
claims, these lawsuits assert claims for personal injury or wrongful death in connection with the accident and the spill response, commercial and
economic injury, damage to real and personal property, breach of contract and violations of statutes, including, but not limited, to alleged violations of
US securities and environmental statutes. Until further fact and expert disclosures occur, court rulings clarify the issues in dispute, liability and damage
trial activity nears or progresses, or other actions such as further possible settlements occur, it is not possible given these uncertainties to arrive at a
range of outcomes or a reliable estimate of the liabilities that may accrue to BP in connection with or as a result of these lawsuits. Therefore no
amounts have been provided for these items as at 31 December 2013. See Legal proceedings on page 257 for further information.
For those items not covered by the trust fund it is not possible to measure reliably any obligation in relation to other litigation or potential fines and
penalties except, subject to certain assumptions detailed above, for those relating to the Clean Water Act. There are a number of federal and state
environmental and other provisions of law, other than the Clean Water Act, under which one or more governmental agencies could seek civil fines and
penalties from BP. For example, a complaint filed by the United States sought to reserve the ability to seek penalties and other relief under a number of
other laws. Given the unsubstantiated nature of certain claims that may be asserted, it is not possible at this time to determine whether and to what
extent any such claims would be successful or what penalties or fines would be assessed. Therefore no amounts have been provided for these items.
BP Annual Report and Form 20-F 2013
143
F
i
n
a
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i
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m
e
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t
s
2. Significant event – Gulf of Mexico oil spill – continued
Under the settlement agreements with Anadarko and MOEX, and with Cameron International, the designer and manufacturer of the Deepwater
Horizon blowout preventer, with M-I L.L.C. (M-I), the mud contractor, and with Weatherford, the designer and manufacturer of the float collar used on
the Macondo well, BP has agreed to indemnify Anadarko, MOEX, Cameron, M-I and Weatherford for certain claims arising from the accident. It is
therefore possible that BP may face claims under these indemnities, but it is not currently possible to reliably measure any obligation in relation to such
claims and therefore no amount has been provided as at 31 December 2013.
The magnitude and timing of all possible obligations in relation to the Gulf of Mexico oil spill continue to be subject to a very high degree of uncertainty
as described further in Risk factors on page 51. Any such possible obligations are therefore contingent liabilities and, at present, it is not practicable to
estimate their magnitude or possible timing of payment. Furthermore, other material unanticipated obligations may arise in future in relation to the
incident.
Impact upon the group income statement
The amount of the provision recognized during the year can be reconciled to the charge to the income statement as follows:
Net increase in provision
Derecognition of provision for items that cannot be reliably estimated
Change in discount rate relating to provisions
Costs charged directly to the income statement
Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset, net
Settlements credited to the income statement
(Profit) loss before interest and taxation
Finance costs
(Profit) loss before taxation
2013
2,239
(379)
(5)
136
–
–
(1,542)
(19)
430
39
469
2012
6,868
(794)
–
257
–
–
(1,191)
(145)
4,995
19
5,014
$ million
Cumulative since
the incident
44,551
(1,173)
17
4,244
19,580
283
(19,338)
(5,681)
42,483
193
42,676
2011
5,183
–
17
512
–
43
(4,038)
(5,517)
(3,800)
58
(3,742)
The group income statement for 2013 includes a pre-tax charge of $469 million (2012 pre-tax charge of $5,014 million) in relation to the Gulf of Mexico
oil spill. The costs charged in 2013 relate primarily to the ongoing costs of operating the Gulf Coast Restoration Organization (GCRO) and increases in
legal costs. Finance costs of $39 million (2012 $19 million) reflect the unwinding of the discount on payables and provisions. The cumulative amount
charged to the income statement to date comprises spill response costs arising in the aftermath of the incident, GCRO operating costs, amounts
charged upon initial recognition of the trust obligation, litigation, claims, environmental and legal costs not paid through the Trust, estimated obligations
for future costs that can be estimated reliably at this time and rights and obligations relating to the trust fund, net of settlements agreed with the
co-owners of the Macondo well and other third parties.
The total amount recognized in the income statement is analysed in the table below.
Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset
Other
Total (credit) charge relating to the trust fund
Environmental – amount provided
– change in discount rate relating to provisions
– costs charged directly to the income statement
Total (credit) charge relating to environmental
Spill response – amount provided
– costs charged directly to the income statement
Total (credit) charge relating to spill response
Litigation and claims – amount provided, net of provision derecognized
– costs charged directly to the income statement
Total charge relating to litigation and claims
Clean Water Act penalties – amount provided
Other costs charged directly to the income statement
Settlements credited to the income statement
(Profit) loss before interest and taxation
Finance costs
(Profit) loss before taxation
2013
–
–
(1,542)
–
(1,542)
47
(5)
–
42
(113)
–
(113)
1,926
–
1,926
–
136
(19)
430
39
469
2012
–
–
(1,191)
–
(1,191)
801
–
–
801
109
9
118
5,164
–
5,164
–
248
(145)
4,995
19
5,014
$ million
Cumulative since
the incident
19,580
283
(19,338)
8
533
2,944
17
70
3,031
11,465
2,839
14,304
25,459
184
25,643
3,510
1,143
(5,681)
42,483
193
42,676
2011
–
43
(4,038)
–
(3,995)
1,167
17
–
1,184
586
85
671
3,430
–
3,430
–
427
(5,517)
(3,800)
58
(3,742)
The total amounts that will ultimately be paid by BP in relation to all obligations relating to the incident are subject to significant uncertainty as
described under Provisions and contingent liabilities above.
144
BP Annual Report and Form 20-F 2013
3. Business combinations
BP undertook a number of minor business combinations in 2013 and 2012 for a total consideration of $67 million and $116 million in cash respectively.
In 2011, BP undertook a number of business combinations with total consideration paid in cash amounting to $11.3 billion, offset by cash acquired of
$0.4 billion. The fair value of contingent consideration payable amounted to $0.1 billion. BP acquired from Reliance Industries Limited (Reliance) a 30%
interest in 21 oil and gas production-sharing agreements (PSAs) operated by Reliance in India for $7,026 million. In addition, we completed the final part
of the transaction with Devon Energy (Devon) for the acquisition of Devon’s equity stake in a number of assets in Brazil for consideration of $3.6 billion
and BP’s Alternative Energy business acquired Companhia Nacional de Açúcar e Álcool (CNAA) in Brazil for consideration of $0.7 billion. There were a
number of other individually insignificant business combinations.
4. Non-current assets held for sale
There were no assets or associated liabilities classified as held for sale as at 31 December 2013. The disposal of the assets and associated liabilities
classified as held for sale at 31 December 2012 completed during 2013.
Impairment losses amounting to $186 million (2012 $2,594 million) were recognized relating to certain assets that were classified as held for sale at
31 December 2012, of which $137 million related to the Carson refinery and associated assets. See Note 5 for further information.
Non-current assets classified as held for sale are not depreciated. It is estimated that the benefit arising from the absence of depreciation for the assets
held for sale at 31 December 2012 until their disposal in 2013 amounted to approximately $201 million (2012 $435 million). In addition, profits of
approximately $738 million (2012 $731 million) were not recognized as a result of the discontinuance of equity accounting for our interest in TNK-BP.
Non-current assets held for sale at 31 December 2012
At 31 December 2012 assets classified as held for sale included property, plant and equipment of $3,663 million, investments in associates of $12,322
million and inventories of $2,377 million.
Within the Upstream segment, BP’s interests in the BP-operated Maclure, Harding and Devenick fields and non-operated interests in the Brae complex
of fields and the Braemar field in the central North Sea were classified as held for sale. In the Downstream segment, the Texas City refinery and
related assets, and the southern part of the US West Coast fuels value chain, including the Carson refinery, were classified as held for sale at
31 December 2012. BP’s investment in TNK-BP was classified as an asset held for sale at 31 December 2012. All of the assets classified as held for
sale at 31 December 2012 were sold during 2013. See Notes 5 and 6 for further information.
5. Disposals and impairment
The following amounts were recognized in the income statement in respect of disposals and impairments.
Gains on sale of businesses and fixed assets
Upstream
Downstream
TNK-BP
Other businesses and corporate
Losses on sale of businesses and fixed assets
Upstream
Downstream
Other businesses and corporate
Impairment losses
Upstream
Downstream
Other businesses and corporate
Impairment reversals
Upstream
Downstream
Other businesses and corporate
2013
2012
371
214
12,500
30
13,115
6,504
152
–
41
6,697
2013
2012
144
78
8
230
1,255
484
218
1,957
(226)
–
–
(226)
109
195
6
310
3,046
2,892
320
6,258
(289)
(1)
(3)
(293)
$ million
2011
3,477
319
–
336
4,132
$ million
2011
49
52
3
104
1,443
599
58
2,100
(146)
–
–
(146)
Impairment and losses on sale of businesses and fixed assets
1,961
6,275
2,058
BP Annual Report and Form 20-F 2013
145
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5. Disposals and impairment – continued
Disposals
As part of the response to the consequences of the Gulf of Mexico oil spill in 2010, the group announced plans to deliver up to $38 billion of disposal
proceeds by the end of 2013. This target was reached during 2012; as at 31 December 2012, BP had announced disposals of $38 billion, and in
addition, the sale of our 50% investment in TNK-BP. During 2013 the group announced that it expects to divest a further $10 billion of assets before
the end of 2015.
Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposed
By segment
Upstream
Downstream
TNK-BP
Other businesses and corporate
2013
18,115
3,884
21,999
1,288
3,991
16,646
74
21,999
2012
9,992
1,606
11,598
10,667
637
–
294
11,598
$ million
2011
3,504
(663)
2,841
1,080
830
–
931
2,841
Proceeds from disposals for 2012 included a deposit of $632 million received in respect of the disposal in 2013 of interests in a number of central
North Sea oil and gas fields. Disposal proceeds for 2011 included the repayment of a deposit of $3,530 million received in 2010 in advance of the
expected sale of our interest in Pan American Energy LLC, which did not complete.
At 31 December 2013, deferred consideration relating to disposals amounted to $23 million receivable within one year (2012 $24 million and 2011
$117 million) and $1,374 million receivable after one year (2012 $1,433 million and 2011 $1,524 million). In addition, contingent consideration relating to
the disposals of the Devenick field and the Texas City refinery amounted to $953 million at 31 December 2013 – see Notes 20 and 26 for further
information.
Upstream
In 2013, the major disposal transaction in the segment was the sale of our interests in the BP-operated Maclure, Harding and Devenick fields and non-
operated interests in the Brae complex of fields and the Braemar field in the central North Sea to TAQA. In addition, we sold our interests in the
Yacheng field in China to Kuwait Foreign Petroleum Exploration Company, as well as other interests in the North Sea and the US.
In 2012, the major disposal transactions were the sale of our interests in the Marlin, Horn Mountain, Holstein, Ram Powell and Diana Hoover fields in
the Gulf of Mexico to Plains Exploration and Production Company, the sale of our interests in the Hugoton and Jayhawk gas production and processing
assets in Kansas, and our interest in the Jonah and Pinedale upstream operations in Wyoming, to LINN Energy, LLC, and the sale of our interests in our
Canadian natural gas liquids (NGL) business to Plains Midstream Canada ULC. In addition, we sold a number of interests in the North Sea, including the
disposal of our Southern Gas Assets to Perenco UK Ltd.
In 2011, the major disposal transactions were the sale of our interests in Colombia to Ecopetrol and Talisman, the sale of our upstream and midstream
assets in Vietnam and our investments in equity-accounted entities in Venezuela to TNK-BP, and the sale of our assets in Pakistan to United Energy
Group. In addition, we completed the disposal of half of the 3.29% interest in the Azeri-Chirag-Gunashli development in Azerbaijan to SOCAR and a
number of interests in the Gulf of Mexico to Marubeni Group.
Downstream
In 2013, gains resulted from the disposal of our global LPG business and closing adjustments on the sales of the Texas City and Carson refineries with
their associated marketing and logistics assets. Losses principally resulted from the disposal of a number of assets, principally in our global fuels
portfolio.
In 2012, gains on disposal resulted from the disposal of our interests in purified terephthalic acid production in Malaysia to Reliance Global Holdings
Pte. Ltd., retail churn in the US and a number of other assets in the segment. Losses resulted from the ongoing costs associated with our US refinery
divestments and the disposal of a number of assets in the segment portfolio.
In 2011, gains on disposal resulted from our disposal of the fuels marketing business in Namibia, Malawi, Zambia and Tanzania to Puma Energy, certain
non-strategic pipelines and terminals in the US and other assets in the segment. Losses resulted from the disposal of a number of assets in the
segment portfolio.
TNK-BP
In 2013, BP disposed of its 50% interest in TNK-BP. See Note 6 for further information.
Other businesses and corporate
In 2011, we disposed of our aluminium business in the US which resulted in a gain.
146
BP Annual Report and Form 20-F 2013
5. Disposals and impairment – continued
Summarized financial information relating to the sale of businesses is shown in the table below. The principal transactions categorized as business
disposals in 2013 were the sales of the Texas City and Carson refineries with their associated marketing and logistics assets. Information relating to
sales of fixed assets is excluded from the table.
Non-current assets
Current assets
Non-current liabilities
Current liabilities
Total carrying amount of net assets disposed
Recycling of foreign exchange on disposal
Costs on disposala
Profit on sale of businessesb
Total consideration
Consideration received (receivable)c
Proceeds from the sale of businesses related to completed transactions
Deposits received (repaid) related to assets classified as held for saled
Disposals completed in relation to which deposits had been received in prior year
Proceeds from the sale of businessese
2013
2,124
2,371
(94)
(62)
4,339
23
13
4,375
69
4,444
(414)
4,030
–
(146)
3,884
2012
610
570
(263)
(232)
685
(15)
39
709
675
1,384
76
1,460
146
–
1,606
$ million
2011
2,085
1,008
(212)
(611)
2,270
8
17
2,295
2,232
4,527
116
4,643
(3,530)
(1,776)
(663)
F
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a 2013 includes pension and other post-retirement benefit plan curtailment gains of $109 million.
b In 2011 a $278-million gain was not recognized in the income statement as it represented an unrealized gain on the sale of business assets in Vietnam to our former associate TNK-BP.
c Consideration received from prior year business disposals or to be received from current year disposals. 2013 includes contingent consideration of $475 million relating to the disposal of the Texas City
refinery.
d 2011 relates to the repayment of a deposit received in advance of $3,530 million following the termination of the sale agreement in respect of the expected sale of our interest in Pan American Energy
LLC.
e Substantially all of the consideration received was in the form of cash and cash equivalents. Proceeds are stated net of cash and cash equivalents disposed of $42 million (2012 $4 million and 2011 $14
million).
Impairment
Upstream
During 2013, the Upstream segment recognized impairment losses of $1,255 million. The main elements were impairment losses of $251 million and
$159 million relating to the Browse project in Australia and the Mad Dog Phase 2 project in the Gulf of Mexico respectively, resulting from the selection
of alternative development scenarios for both projects; write-downs of a number of assets in the North Sea, caused by increases in expected
decommissioning costs, amounting to $253 million in aggregate; a $134-million write-down of pipelines in the North Sea due to cost increases; a
$122-million write-down to fair value less costs to sell based on expected proceeds resulting from a decision to divest our interest in the Polvo field in
Brazil; and other impairment losses amounting to $335 million in total that were not individually significant. These impairment losses were partly offset
by reversals of impairment of certain of our interests in Alaska, the Gulf of Mexico, and the North Sea amounting to $226 million in total, triggered by
reductions in expected decommissioning costs, partly as a result of an increase in the discount rate for provisions.
During 2012, the Upstream segment recognized impairment losses of $3,046 million. The main elements were a $1,082-million write-down of our
interests in the Fayetteville and Woodford shale gas assets in the US, due to reserves revisions, lower values being attributed to recent market
transactions and a fall in the gas price; a $999-million impairment loss relating to the decision to suspend the Liberty project in Alaska; a $706-million
aggregate write-down of a number of assets, primarily in the Gulf of Mexico and North Sea, caused by increases in the decommissioning provision
resulting from continued review of the expected decommissioning costs; a $144-million write-down of certain gas storage assets in Europe due to
changes to the European gas market; and other impairment losses amounting to $116 million in total that were not individually significant. These
impairment losses were partly offset by reversals of impairment of certain of our interests in the Gulf of Mexico amounting to $222 million, triggered
by a decision to divest assets; and other reversals of impairment amounting to $67 million in total that were not individually significant.
During 2011, the Upstream segment recognized impairment losses of $1,443 million. The main elements were a $555-million impairment loss relating
to a number of our interests in the Gulf of Mexico, caused by an increase in the decommissioning provision as a result of further assessments of the
regulations relating to idle infrastructure and a decrease in our assumption of the discount rate for provisions; the $393-million write-down of our
interest in the Fayetteville shale gas asset in the US, triggered by a decrease in value by reference to a sale transaction by a partner of its interest in the
same asset; and the $153-million write-down of our interest in the proposed Denali gas pipeline in Alaska, resulting from a decision not to proceed with
the project. There were several other impairment losses amounting to $342 million in total that were not individually significant. These impairment
losses were partly offset by reversals of impairment of certain of our interests in the Gulf of Mexico and Egypt amounting to $146 million in total,
triggered by an increase in our assumption of long-term oil prices.
Downstream
During 2013, the Downstream segment recognized impairment losses of $484 million which mainly relates to impairments of certain refineries in the
US and elsewhere in our global fuels portfolio.
During 2012, the Downstream segment recognized impairment losses of $2,892 million largely related to assets held for sale for which sales prices
had been agreed, see Note 4 for further information. This impairment loss included $1,552 million relating to the Texas City refinery and associated
assets and $1,042 million relating to the Carson refinery and associated assets.
During 2011, the Downstream segment recognized impairment losses of $599 million, of which $398 million related to assets classified as held for
sale. Other impairment losses, related to retail churn in Europe and other minor asset disposals, amounted to $201 million in total.
Other businesses and corporate
Impairment losses totalling $218 million, $320 million and $58 million were recognized in 2013, 2012 and 2011 respectively related to various assets in
the Alternative Energy business. The amount for 2013 is principally in respect of our US wind business. The amount for 2012 includes $258 million in
respect of the decision not to proceed with an investment in a biofuels production facility under development in the US.
BP Annual Report and Form 20-F 2013
147
6. Disposal of TNK-BP and investment in Rosneft
Disposal of TNK-BP
BP announced on 22 November 2012 that it, Rosneft and Rosneftegaz – the Russian state-owned parent company of Rosneft – had signed definitive
and binding sale and purchase agreements (SPAs) for the sale of BP’s 50% interest in TNK-BP to Rosneft, and for BP’s further investment in Rosneft.
The transaction would consist of three tranches:
• BP to sell its 50% shareholding in TNK-BP to Rosneft for cash consideration of $25.4 billion (which included a dividend of $0.7 billion received from
TNK-BP in December 2012) and Rosneft shares representing a 3.04% stake in Rosneft.
• BP would use $4.8 billion of the cash consideration to acquire a further 5.66% stake in Rosneft from the Russian government at a price of $8 per
share (representing a premium of 12% to the Rosneft share price on the bid date of 18 October 2012).
• BP would use $8.3 billion of the cash consideration to acquire a further 9.8% stake in Rosneft from a Rosneft subsidiary at a price of $8 per share.
The net result of the overall transaction was that BP would receive $12.3 billion in cash (including $0.7 billion of TNK-BP dividends received by BP in
December 2012) and acquire an 18.5% shareholding in Rosneft. Combined with BP’s existing 1.25% shareholding, this would result in BP owning
19.75% of Rosneft.
On completion, the transactions between BP, Rosneft and the Rosneft subsidiary were instead settled on a net basis, so that BP received the 9.80%
stake in Rosneft directly rather than receiving and immediately paying $8.3 billion in cash; however, the net result was the same.
BP accounts for its investment in Rosneft as an associate, and so equity accounts for its share of Rosneft’s earnings, production and reserves. See
Note 18 for more information on BP’s investment in Rosneft.
The gain on disposal of BP’s investment in TNK-BP, recognized in the TNK-BP segment in 2013, was $12.5 billion as shown in the table below.
Agreed cash disposal proceeds
Amount settled net in Rosneft shares (9.80% stake)
TNK-BP dividend received by BP in December 2012
Interest on cash proceeds
Disposal proceeds received in cash
Shares in Rosneft received (9.80% and 3.04% stake)
Consideration received
Less: carrying value of investment in TNK-BP
Deferral of gain
Gain on existing 1.25% investment in Rosneft
Other
Gain on disposal of investment in TNK-BP
$ million
25,425
(8,309)
(709)
239
16,646
10,755
27,401
(12,393)
15,008
(2,959)
523
(72)
12,500
Disposal proceeds of $4.9 billion were used to purchase the 5.66% stake in Rosneft from Rosneftegaz ($4.8 billion described above plus $0.1 billion of
interest). The net cash inflow relating to the transaction included in net cash flow from investing activities in the cash flow statement was $11.8 billion.
Part of the gain arising on the disposal, amounting to $3.0 billion, was deferred due to BP selling its investment in TNK-BP to Rosneft, which in turn is
now accounted for by BP as an associate. The deferred gain will be released to BP’s income statement over time as the TNK-BP assets are
depreciated or amortized.
Investment in Rosneft
BP’s investment in Rosneft is included in the group balance sheet within investments in associates, as described in Note 1. The investment is
measured at cost less the deferred gain described above, plus post-acquisition changes in BP’s share of Rosneft’s net assets. The amount recognized
as BP’s initial investment in Rosneft was determined as shown in the table below.
Shares in Rosneft received
Shares purchased from Rosneftegaz
Value of agreements to purchase Rosneft shares accounted for as derivatives (see Note 26)
Deferred gain
Amount included in capital expenditure
Value of existing 1.25% investment in Rosneft
Investment in Rosneft on completion
$ million
10,755
4,871
(726)
(2,959)
11,941
1,006
12,947
The exercise to determine BP’s share of the fair value of Rosneft’s identifiable net assets and the consequent impact recognized via equity accounting
in BP’s income statement has been completed and the results are reflected in these financial statements.
148
BP Annual Report and Form 20-F 2013
7. Segmental analysis
The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2013, BP had three reportable segments:
Upstream, Downstream and Rosneft.
Upstream’s activities include oil and natural gas exploration, field development and production; midstream transportation, storage and processing; and
the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs).
Downstream’s activities include the refining, manufacturing, marketing, transportation, and supply and trading of crude oil, petroleum, petrochemicals
products and related services to wholesale and retail customers.
During 2013, BP completed transactions for the sale of BP’s interest in TNK-BP to Rosneft, and for BP’s further investment in Rosneft. BP’s interest in
Rosneft is accounted for using the equity method and is reported as a separate operating segment, reflecting the way in which the investment is
managed.
Other businesses and corporate comprises the Alternative Energy business, the group’s shipping and treasury functions, and corporate activities
worldwide. The Alternative Energy business is an operating segment which is reported within Other businesses and corporate as it does not meet the
materiality thresholds for separate segment reporting.
The Gulf Coast Restoration Organization (GCRO), which manages all aspects of our response to the 2010 Gulf of Mexico incident, reports directly to
the group chief executive and is overseen by a board committee, however it is not an operating segment.
The accounting policies of the operating segments are the same as the group’s accounting policies described in Note 1. However, IFRS requires that
the measure of profit or loss disclosed for each operating segment is the measure that is provided regularly to the chief operating decision maker for
the purposes of performance assessment and resource allocation. For BP, this measure of profit or loss is replacement cost profit or loss before
interest and tax which reflects the replacement cost of supplies by excluding from profit or loss inventory holding gains and lossesa. Replacement cost
profit or loss for the group is not a recognized measure under IFRS.
Sales between segments are made at prices that approximate market prices, taking into account the volumes involved. Segment revenues and
segment results include transactions between business segments. These transactions and any unrealized profits and losses are eliminated on
consolidation, unless unrealized losses provide evidence of an impairment of the asset transferred. Sales to external customers by region are based on
the location of the seller. The UK region includes the UK-based international activities of Downstream.
All surpluses and deficits recognized on the group balance sheet in respect of pension and other post-retirement benefit plans are allocated to Other
businesses and corporate. However, the periodic expense relating to these plans is allocated to the other operating segments based upon the
business in which the employees work.
Certain financial information is provided separately for the US as this is an individually material country for BP, and for the UK as this is BP’s country of
domicile.
F
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a Inventory holding gains and losses represent the difference between the cost of sales calculated using the average cost to BP of supplies acquired during the period and the cost of sales calculated on
the first-in first-out (FIFO) method after adjusting for any changes in provisions where the net realizable value of the inventory is lower than its cost. Under the FIFO method, which we use for IFRS
reporting, the cost of inventory charged to the income statement is based on its historic cost of purchase, or manufacture, rather than its replacement cost. In volatile energy markets, this can have a
significant distorting effect on reported income. The amounts disclosed represent the difference between the charge (to the income statement) for inventory on a FIFO basis (after adjusting for any
related movements in net realizable value provisions) and the charge that would have arisen if an average cost of supplies was used for the period. For this purpose, the average cost of supplies during
the period is principally calculated on a monthly basis by dividing the total cost of inventory acquired in the period by the number of barrels acquired. The amounts disclosed are not separately reflected
in the financial statements as a gain or loss. No adjustment is made in respect of the cost of inventories held as part of a trading position and certain other temporary inventory positions.
BP Annual Report and Form 20-F 2013
149
7. Segmental analysis – continued
By segment
Segment revenues
Upstream
Downstream
Rosneft
TNK-BP
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2013
Total
group
Sales and other operating revenues
Less: sales and other operating revenues
70,374
351,195
between segments
(42,327)
(1,045)
–
–
28,047
1,027
76
350,150
195
93
–
2,058
–
–
–
–
–
–
1,805
(866)
939
(91)
113
–
–
–
–
–
(44,238)
379,136
44,238
–
–
–
–
379,136
3,189
282
16,657
4
16,661
2,919
(194)
2,725
2,153
(100)
2,053
12,500
–
12,500
(2,319)
–
(2,319)
(430)
–
(430)
579
–
579
Third party sales and other operating
revenues
Equity-accounted earnings
Interest income
Segment results
Replacement cost profit (loss) before
interest and taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions
and other post-retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
US
Non-US
Impairment losses
Impairment reversals
Fair value (gain) loss on embedded
derivatives
Charges for provisions, net of write-back of
unused provisions, including change in
discount rate
Segment assets
Equity-accounted investments
Additions to non-current assets
Additions to other investments
Element of acquisitions not related to non-
current assets
Additions to decommissioning asset
32,059
(290)
31,769
(1,068)
(480)
30,221
4,466
9,044
1,957
(226)
(459)
2,581
25,835
36,916
41
39
(384)
–
–
–
–
–
–
–
–
–
36,612
3,538
7,514
1,255
(226)
(459)
747
1,343
484
–
–
161
270
–
–
–
–
–
–
7,780
19,499
3,302
13,681
4,449
11,941
–
–
–
–
–
–
–
–
–
181
187
218
–
–
–
–
–
–
–
295
1,855
1,072
1,027
1,050
–
–
–
Capital expenditure and acquisitions
19,115
4,506
11,941
a See explanation of inventory holding gains and losses on page 149.
150
BP Annual Report and Form 20-F 2013
7. Segmental analysis – continued
By segment
Segment revenues
Sales and other operating revenues
Less: sales and other operating revenues between
segments
Third party sales and other operating revenues
Equity-accounted earnings
Interest income
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-
retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
US
Non-US
Impairment losses
Impairment reversals
Fair value (gain) loss on embedded derivatives
Charges for provisions, net of write-back of unused
provisions, including change in discount rate
Segment assets
Equity-accounted investments
Additions to non-current assets
Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2012
Total
group
1,985
(899)
1,086
(67)
104
–
–
–
–
–
(44,836)
375,765
44,836
–
–
–
–
375,765
3,935
319
Upstream
Downstream
TNK-BP
72,225
346,391
(42,572)
(1,365)
–
–
345,026
101
108
–
2,986
–
29,653
915
107
22,491
(104)
22,387
2,864
(487)
2,377
3,373
(3)
3,370
(2,794)
–
(2,794)
(4,995)
–
(4,995)
(576)
–
(576)
3,437
6,918
3,046
(289)
(347)
586
1,343
2,892
(1)
–
897
141
7,329
22,603
3,212
5,246
–
–
–
–
–
–
–
–
–
213
190
320
(3)
–
–
–
–
–
–
505
6,074
1,071
1,419
1,435
–
–
–
–
–
–
–
–
–
–
–
–
20,363
(594)
19,769
(1,072)
(566)
18,131
4,236
8,451
6,258
(293)
(347)
7,617
11,612
29,268
33
(72)
(4,025)
25,204
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Capital expenditure and acquisitions
18,520
5,249
a See explanation of inventory holding gains and losses on page 149.
BP Annual Report and Form 20-F 2013
151
7. Segmental analysis – continued
By segment
Segment revenues
Sales and other operating revenues
Less: sales and other operating revenues between
segments
Third party sales and other operating revenues
Equity-accounted earnings
Interest income
Segment results
Replacement cost profit (loss) before interest and taxation
Inventory holding gains (losses)a
Profit (loss) before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-
retirement benefits
Profit before taxation
Other income statement items
Depreciation, depletion and amortization
US
Non-US
Impairment losses
Impairment reversals
Fair value (gain) loss on embedded derivatives
Charges for provisions, net of write-back of unused
provisions, including change in discount rate
Segment assets
Equity-accounted investments
Additions to non-current assets
Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset
Other
businesses
and
corporate
Gulf of
Mexico
oil spill
response
Consolidation
adjustment
and
eliminations
$ million
2011
Total
group
2,957
(869)
2,088
(33)
146
(2,468)
15
(2,453)
151
174
58
–
123
942
1,024
1,864
1,853
–
–
–
–
–
(47,031)
375,713
47,031
–
–
–
–
375,713
5,683
244
3,800
–
3,800
(113)
–
(113)
–
–
–
–
–
5,200
–
–
–
–
–
–
–
–
–
–
–
–
37,181
2,634
39,815
(1,187)
(400)
38,228
4,212
7,145
2,100
(146)
(68)
6,728
21,594
40,958
27
(1,089)
(7,937)
31,959
Upstream
Downstream
TNK-BP
75,754
344,033
(44,766)
30,988
1,150
(10)
26,358
81
26,439
(1,396)
342,637
381
108
5,470
2,487
7,957
–
–
–
4,185
–
4,134
51
4,185
3,201
5,540
1,443
(146)
(191)
860
1,431
599
–
–
213
373
–
–
–
–
–
–
7,301
34,813
3,256
10,013
4,281
–
–
Capital expenditure and acquisitions
25,821
4,285
a See explanation of inventory holding gains and losses on page 149.
152
BP Annual Report and Form 20-F 2013
7. Segmental analysis – continued
By geographical area
Revenues
US
Non-US
$ million
2013
Total
Third party sales and other operating revenuesa
128,764
250,372
379,136
Other income statement items
Production and similar taxes
Results
Replacement cost profit before interest and taxation
Non-current assets
Other non-current assetsb c
Other investments
Loans
Trade and other receivables
Derivative financial instruments
Deferred tax assets
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions
a Non-US region includes UK $82,381 million.
b Non-US region includes UK $18,967 million.
c Excluding financial instruments, deferred tax assets and defined benefit pension plan surpluses.
By geographical area
Revenues
1,112
5,935
7,047
3,114
28,945
32,059
70,228
124,439
194,667
1,565
763
5,985
3,509
985
1,376
208,850
9,176
27,436
36,612
US
Non-US
$ million
2012
Total
Third party sales and other operating revenuesa
130,940
244,825
375,765
Other income statement items
Production and similar taxes
Results
Replacement cost profit before interest and taxation
Non-current assets
Other non-current assetsb c
Other investments
Loans
Trade and other receivables
Derivative financial instruments
Deferred tax assets
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions
a Non-US region includes UK $75,364 million.
b Non-US region includes UK $17,545 million.
c Excluding financial instruments, deferred tax assets and defined benefit pension plan surpluses.
1,472
6,686
8,158
180
20,183
20,363
66,751
107,844
174,595
2,704
642
5,961
4,294
874
12
189,082
10,541
14,663
25,204
F
i
n
a
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c
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a
l
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m
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n
t
s
BP Annual Report and Form 20-F 2013
153
7. Segmental analysis – continued
By geographical area
Revenues
US
Non-US
$ million
2011
Total
Third party sales and other operating revenuesa
131,488
244,225
375,713
Other income statement items
Production and similar taxes
Results
1,854
6,426
8,280
Replacement cost profit before interest and taxation
10,202
26,979
37,181
Non-current assets
Other non-current assetsb c
Other investments
Loans
Trade and other receivables
Derivative financial instruments
Deferred tax assets
Defined benefit pension plan surpluses
Total non-current assets
Capital expenditure and acquisitions
a Non-US region includes UK $75,816 million.
b Non-US region includes UK $18,363 million.
c Excluding financial instruments, deferred tax assets and defined benefit pension plan surpluses.
8. Income statement analysis
Interest and other income
Interest income
Other incomea
Currency exchange losses (gains) charged (credited) to the income statementb
Expenditure on research and development
Finance costs
Interest payable
Capitalized at 2% (2012 2.25% and 2011 2.63%)c
Unwinding of discount on provisionsd
Unwinding of discount on other payablesd
66,523
113,323
179,846
2,635
824
5,738
5,038
611
17
194,709
8,931
23,028
31,959
2013
2012
282
495
777
180
707
1,082
(238)
147
77
1,068
319
1,358
1,677
106
674
1,234
(390)
140
88
1,072
$ million
2011
244
444
688
(69)
636
1,151
(349)
244
141
1,187
a 2012 includes $709 million of dividends received from TNK-BP. See Note 6 for further information.
b Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
c Tax relief on capitalized interest is approximately $62 million (2012 $93 million and 2011 $107 million).
d Unwinding of discount on provisions relating to the Gulf of Mexico oil spill was $1 million (2012 $7 million and 2011 $6 million) and unwinding of discount on other payables relating to the Gulf of
Mexico oil spill was $38 million (2012 $12 million and 2011 $52 million). See Note 2 for further information on the financial impacts of the Gulf of Mexico oil spill.
9. Operating leases
In the case of an operating lease entered into by BP as the operator of a joint operation, the amounts shown in the tables below represent the net
operating lease expense and net future minimum lease payments. These net amounts are after deducting amounts reimbursed, or to be reimbursed,
by joint operators, whether the joint operators have co-signed the lease or not. Where BP is not the operator of a joint operation, BP’s share of the
lease expense and future minimum lease payments is included in the amounts shown, whether BP has co-signed the lease or not.
The table below shows the expense for the year in respect of operating leases.
Minimum lease payments
Contingent rentals
Sub-lease rentals
154
BP Annual Report and Form 20-F 2013
2013
5,961
(50)
(88)
5,823
2012
5,257
(79)
(228)
4,950
$ million
2011
4,868
(97)
(153)
4,618
9. Operating leases – continued
The future minimum lease payments at 31 December 2013, before deducting related rental income from operating sub-leases of $223 million (2012
$271 million), are shown in the table below. This does not include future contingent rentals. Where the lease rentals are dependent on a variable factor,
the future minimum lease payments are based on the factor as at inception of the lease.
Future minimum lease payments
Payable within
1 year
2 to 5 years
Thereafter
2013
5,188
10,408
3,590
19,186
$ million
2012
4,533
9,735
4,195
18,463
The group enters into operating leases of ships, plant and machinery, commercial vehicles and land and buildings. Typical durations of the leases are as
follows:
Ships
Plant and machinery
Commercial vehicles
Land and buildings
Years
up to 15
up to 10
up to 15
up to 40
The group has entered into a number of structured operating leases for ships and in most cases the lease rental payments vary with market interest
rates. The variable portion of the lease payments above or below the amount based on the market interest rate prevailing at inception of the lease is
treated as contingent rental expense. The group also routinely enters into bareboat charters, time-charters and voyage-charters for ships on standard
industry terms.
The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Upstream segment. At 31 December 2013,
the future minimum lease payments relating to drilling rigs amounted to $8,776 million (2012 $8,527 million).
Commercial vehicles hired under operating leases are primarily railcars. Retail service station sites and office accommodation are the main items in the
land and buildings category.
The terms and conditions of these operating leases do not impose any significant financial restrictions on the group. Some of the leases of ships and
buildings allow for renewals at BP’s option, and some of the group’s operating leases contain escalation clauses.
10. Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration for and
evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment.
F
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n
a
n
c
i
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l
s
t
a
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m
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t
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Exploration and evaluation costs
Exploration expenditure written offa
Other exploration costs
Exploration expense for the year
Impairment losses
Impairment reversals
Intangible assets – exploration and appraisal expenditure
Liabilities
Net assets
Capital expenditure
Net cash used in operating activities
Net cash used in investing activities
2013
2012
2,710
731
3,441
253
–
745
730
1,475
–
(42)
$ million
2011
1,024
496
1,520
7
–
20,865
23,434
20,433
212
287
306
20,653
23,147
20,127
4,464
731
4,275
5,176
730
5,010
8,926
496
8,571
a 2013 included an $845-million write-off relating to the value ascribed to block BM-CAL-13 offshore Brazil as a result of the Pitanga exploration well not encountering commercial quantities of oil or gas
and a $257-million write-off of costs relating to the Risha concession in Jordan as our exploration activities did not establish the technical basis for a development project in the concession. For further
information see Upstream – Exploration on page 28.
The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2013 is shown in the table
below.
Carrying amount
$1-2 billion
$2-3 billion
$3-4 billion
$4-5 billion
Location
Angola; US – North America gas
Canada; Egypt; India
Brazil
US – Gulf of Mexico
BP Annual Report and Form 20-F 2013
155
11. Taxation
Tax on profit
Current tax
Charge for the year
Adjustment in respect of prior years
Deferred tax
Origination and reversal of temporary differences in the current year
Adjustment in respect of prior years
2013
2012
5,724
61
5,785
529
149
678
6,664
252
6,916
67
(103)
(36)
$ million
2011
7,500
111
7,611
5,523
(515)
5,008
Tax charge on profit
6,463
6,880
12,619
In 2013, the total tax charge recognized within other comprehensive income was $1,374 million (2012 $270 million credit and 2011 $1,490 million
credit), and the total tax credit recognized directly in equity was $33 million (2012 $6 million credit and 2011 $7 million credit). See Note 32 for further
information.
Reconciliation of the effective tax rate
The following table provides a reconciliation of the UK statutory corporation tax rate to the effective tax rate of the group on profit before taxation. With
effect from 1 April 2013 the UK statutory corporation tax rate reduced from 24% to 23% on profits arising from activities outside the North Sea.
Profit before taxation
Tax charge on profit
Effective tax rate
UK statutory corporation tax rate
Increase (decrease) resulting from
UK supplementary and overseas taxes at higher or lower ratesa
Tax reported in equity-accounted entities
Adjustments in respect of prior years
Movement in deferred tax not recognized
Tax incentives for investment
Gulf of Mexico oil spill non-deductible costs
Permanent differences relating to disposalsb
Foreign exchange
Other
Effective tax rate
2013
30,221
6,463
21%
2012
18,131
6,880
38%
$ million
2011
38,228
12,619
33%
% of profit before taxation
23
4
(2)
1
2
(2)
–
(8)
2
1
21
24
12
(5)
1
2
(2)
8
–
(1)
(1)
38
26
14
(3)
(1)
–
(1)
–
(2)
1
(1)
33
a Jurisdictions which contribute significantly to this item are Angola, with an applicable statutory tax rate of 50%, the UK, currently with an applicable statutory tax rate of 62% for North Sea activities, and
Trinidad and Tobago, with an applicable statutory tax rate of 55%.
b For 2013, this relates to the non-taxable gain on disposal of our investment in TNK-BP; for 2011, this mainly relates to the sale of our Upstream interests in Columbia.
156
BP Annual Report and Form 20-F 2013
11. Taxation – continued
Deferred tax
Deferred tax liability
Depreciation
Pension plan surpluses
Other taxable temporary differences
Deferred tax asset
Pension plan and other post-retirement benefit plan deficits
Decommissioning, environmental and other provisions
Derivative financial instruments
Tax credits
Loss carry forward
Other deductible temporary differences
Net deferred tax charge (credit) and net deferred tax liability
Of which – deferred tax liabilities
– deferred tax assets
Analysis of movements during the year in the net deferred tax liability
At 1 January
Exchange adjustments
Charge (credit) for the year on profit
Charge (credit) for the year in other comprehensive income
Charge (credit) for the year in equity
Acquisitions
Reclassified as assets/liabilities held for sale
Deletions
At 31 December
Income statement
$ million
Balance sheet
2013
2012
2011
2013
2012
(474)
(691)
(199)
(1,364)
787
1,385
30
(174)
(343)
357
2,042
678
(75)
–
(2,239)
(2,314)
(33)
1,872
(7)
1,802
(911)
(445)
2,278
4,774
–
141
4,915
224
(1,443)
24
(401)
(223)
1,912
93
(36)
5,008
31,551
284
3,653
35,488
(2,026)
(11,301)
(579)
(888)
(2,585)
(1,655)
(19,034)
16,454
17,439
985
2013
14,369
43
678
1,397
(33)
–
–
–
16,454
32,065
–
3,671
35,736
(3,421)
(12,705)
(281)
(714)
(2,214)
(2,032)
(21,367)
14,369
15,243
874
$ million
2012
14,609
(27)
(36)
(272)
4
11
48
32
14,369
F
i
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a
n
c
i
a
l
s
t
a
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e
m
e
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t
s
A summary of temporary differences, unused tax credits and unused tax losses for which deferred tax has not been recognized is shown in the table
below.
At 31 December
Unused tax lossesa
Unused tax credits
of which – arising in the UKb
– arising in the USc
Other deductible temporary differencesd
Other taxable temporary differences associated with investments in subsidiaries and equity-accounted entities
2013
1.8
18.0
16.3
1.7
11.2
0.5
$ billion
2012
0.9
18.3
16.0
2.3
7.0
0.5
a Substantially all the tax losses have no fixed expiry date.
b The UK tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with high tax rates. No deferred tax asset has been recognized on these tax credits as they are unlikely
to have value in the future; UK taxes on these overseas branches are largely mitigated by double tax relief on the overseas tax. These tax credits have no fixed expiry date.
c The US tax credits expire 10 years after generation and will all expire in the period 2015-2021.
d Other deductible temporary differences of $0.7 billion are expected to expire in the period 2014-2020, the remainder do not have an expiry date.
Benefit of previously unrecognized deferred tax on current year tax charge
Current tax benefit relating to the utilization of previously unrecognized tax losses
Current tax benefit relating to the utilization of previously unrecognized tax credits
Deferred tax benefit relating to the recognition of previously unrecognized tax credits
2013
–
0.2
0.2
2012
–
0.4
0.1
$ billion
2011
0.1
0.1
–
BP Annual Report and Form 20-F 2013
157
12. Dividends
The quarterly dividend expected to be paid on 28 March 2014 in respect of the fourth quarter 2013 is 9.5 cents per ordinary share ($0.57 per American
Depositary Share (ADS)). The corresponding amount in sterling will be announced on 17 March 2014. A scrip dividend alternative is available, allowing
shareholders to elect to receive their dividend in the form of new ordinary shares and ADS holders in the form of new ADSs.
Dividends announced and paid in cash
Preference shares
Ordinary shares
March
June
September
December
Dividend announced, payable in March 2014
Pence per share
Cents per share
2013
2012
2011
2013
2012
2011
2013
2012
$ million
2011
2
2
2
6.0013
5.8342
5.7630
5.8008
5.0958
5.1498
5.0171
5.5890
4.3372
4.2809
4.3160
4.4694
23.3993
20.8517
17.4035
9.0
9.0
9.0
9.5
36.5
9.5
8.0
8.0
8.0
9.0
7.0
7.0
7.0
7.0
33.0
28.0
1,621
1,399
1,245
1,174
5,441
1,733
1,211
1,448
1,417
1,216
5,294
808
794
1,224
1,244
4,072
The details of the scrip dividends issued are shown in the table below.
Number of shares issued (thousand)
Value of shares issued ($ million)
2013
202,124
1,470
2012
138,406
982
2011
165,601
1,219
The financial statements for the year ended 31 December 2013 do not reflect the dividend announced on 4 February 2014 and expected to be paid in
March 2014; this will be treated as an appropriation of profit in the year ended 31 December 2014.
13. Earnings per ordinary share
Basic earnings per share
Diluted earnings per share
2013
123.87
123.12
2012
57.89
57.50
Cents per share
2011
133.35
131.74
Basic earnings per ordinary share amounts are calculated by dividing the profit for the year attributable to ordinary shareholders by the weighted
average number of ordinary shares outstanding during the year. The average number of shares outstanding excludes treasury shares and the shares
held by the Employee Share Ownership Plan trusts (ESOPs) and includes certain shares that will be issuable in the future under employee share-based
payment plans.
For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the dilutive effect of
shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method.
Profit attributable to BP shareholders
Less: dividend requirements on preference shares
Profit for the year attributable to BP ordinary shareholders
Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans
2013
23,451
2
23,449
2012
11,017
2
11,015
$ million
2011
25,212
2
25,210
Shares thousand
2013
2012
2011
18,931,021
115,152
19,046,173
19,027,929
129,959
19,157,888
18,904,812
231,388
19,136,200
The number of ordinary shares outstanding at 31 December 2013, excluding treasury shares and the shares held by the ESOPs, and including certain
shares that will be issuable in the future under employee share-based payment plans was 18,611,489,958. Between 31 December 2013 and
18 February 2014, the latest practicable date before the completion of these financial statements, there was a net decrease of 171,061,543 in the
number of ordinary shares outstanding as a result of share issues in relation to employee share-based payment plans. During the same period, the
group repurchased 195 million of its own ordinary shares as part of the share repurchase programme announced on 22 March 2013.
Employee share-based payment plans
The group operates share and share option plans for directors and certain employees to obtain ordinary shares and ADSs in the company. Information
on these plans for directors is shown in the Directors remuneration report on page 81.
158
BP Annual Report and Form 20-F 2013
13. Earnings per ordinary share – continued
The following table shows the number of shares potentially issuable under employee share option plans, including the number of options outstanding,
the number of options exercisable at the end of each year, and the corresponding weighted average exercise prices. The dilutive effect of the
employee share option plans at 31 December included in the diluted earnings per share is also shown.
Share options
Outstanding
Exercisable
Dilutive effect
2013
Weighted
average
exercise
price $
7.71
10.01
n/a
2012
Weighted
average
exercise
price $
7.62
9.33
n/a
Number of
optionsa b
thousand
324,096
159,419
16,435
Number of
optionsa b
thousand
286,725
127,290
23,169
a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2013, the quoted market price of one BP ordinary share was $8.10 (2012 $6.94).
In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior leaders and
certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net notional dividends
which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into shares, but special arrangements
apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each year under employee share plans are
shown in the table below. The dilutive effect of the employee share plans at 31 December included in the diluted earnings per share is also shown.
Shares
Vesting
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
Dilutive effect
2013
2012
Number of
sharesa
thousand
35,442
120,056
115,387
14,231
123
285,239
95,014
Number of
sharesa
thousand
29,138
67,593
120,621
25,066
233
242,651
95,683
a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net decrease of 32,378,757 in the number of potential ordinary shares in relation to employee share-based payment plans between
31 December 2013 and 18 February 2014.
F
i
n
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BP Annual Report and Form 20-F 2013
159
14. Property, plant and equipment
Cost
At 1 January 2013
Exchange adjustments
Additions
Acquisitions
Transfers
Deletions
At 31 December 2013
Depreciation
At 1 January 2013
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Transfers
Deletions
At 31 December 2013
Land
and land
improvements
Buildings
3,279
(4)
120
–
–
(20)
3,375
514
(6)
37
10
–
–
(5)
550
2,812
(26)
286
–
–
(45)
3,027
1,023
(1)
129
20
–
–
(30)
1,141
Oil and
gas
properties
171,772
–
14,272
–
4,365
(2,718)
187,691
87,965
–
10,334
611
(209)
365
(2,003)
97,063
45,200
(235)
4,386
8
–
(447)
48,912
18,628
(61)
1,616
525
–
–
(330)
20,378
Net book amount at 31 December 2013
2,825
1,886
90,628
28,534
Plant,
machinery
and
equipment
Fixtures,
fittings
and office
equipment
Transportation
Oil depots,
storage
tanks and
service
stations
$ million
Total
248,904
(351)
20,039
8
4,365
(4,079)
268,886
123,573
(96)
13,243
1,361
(226)
365
(3,024)
135,196
9,059
(36)
625
–
–
(257)
9,391
4,915
(7)
502
35
–
–
(184)
5,261
4,130
133,690
8,611
272
533
–
–
(2)
(355)
9,059
4,571
151
504
7
(1)
(2)
(315)
4,915
248,922
728
23,040
61
1,306
(19,727)
(5,426)
248,904
125,491
431
12,370
3,343
(222)
(13,938)
(3,902)
123,573
4,144
125,331
4,040
123,431
3,346
5
299
–
–
(474)
3,176
2,119
7
278
–
–
–
(434)
1,970
1,206
3,140
28
314
–
–
–
(136)
3,346
1,940
25
289
–
–
–
(135)
2,119
1,227
1,200
13,436
(55)
51
–
–
(118)
13,314
8,409
(28)
347
160
(17)
–
(38)
8,833
4,481
12,753
8
902
15
–
(172)
(70)
13,436
8,149
6
320
70
–
(126)
(10)
8,409
5,027
4,604
3,169
86
120
–
–
–
(96)
3,279
511
8
33
8
–
–
(46)
514
2,765
2,658
2,942
14
387
–
–
–
(531)
2,812
1,411
13
123
–
–
–
(524)
1,023
1,789
1,531
176,988
–
16,303
44
1,306
(19,410)
(3,459)
171,772
91,994
–
9,659
2,765
(221)
(13,774)
(2,458)
87,965
83,807
84,994
41,319
320
4,481
2
–
(143)
(779)
45,200
16,915
228
1,442
493
–
(36)
(414)
18,628
26,572
24,404
–
–
7
9
187
157
265
254
–
–
4
9
–
–
463
429
27,900
29,203
Cost
At 1 January 2012
Exchange adjustments
Additions
Acquisitions
Transfers
Reclassified as assets held for sale
Deletions
At 31 December 2012
Depreciation
At 1 January 2012
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Reclassified as assets held for sale
Deletions
At 31 December 2012
Net book amount at 31 December 2012
Net book amount at 1 January 2012
Assets held under finance leases at net book amount
included above
At 31 December 2013
At 31 December 2012
Assets under construction included above
At 31 December 2013
At 31 December 2012
160
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15. Goodwill and impairment review of goodwill
Cost
At 1 January
Exchange adjustments
Acquisitions
Reclassified as assets held for sale
Deletions
At 31 December
Impairment losses
At 1 January
Impairment losses for the year
Reclassified as assets held for sale
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
Impairment review of goodwill
Goodwill at 31 December
Upstream
Downstream
Other businesses and corporate
2013
12,804
46
44
–
(43)
12,851
614
56
–
–
670
12,181
12,190
2013
7,812
4,277
92
$ million
2012
14,041
160
25
(1,327)
(95)
12,804
1,612
–
(977)
(21)
614
12,190
12,429
$ million
2012
7,862
4,168
160
12,181
12,190
Goodwill acquired through business combinations has been allocated to groups of cash-generating units that are expected to benefit from the
synergies of the acquisition. For Upstream, goodwill is allocated to all oil and gas assets in aggregate at the segment level. For Downstream, goodwill
has been allocated to the Rhine fuels value chain (FVC), Lubricants and Other.
In assessing whether goodwill has been impaired, the carrying amount of the cash-generating unit (CGU) or groups of CGUs (including goodwill) is
compared with the recoverable amount of the CGU or groups of CGUs. The recoverable amount is the higher of fair value less costs to sell and value in
use. In the absence of readily available information about the fair value of a cash-generating unit, the recoverable amount is deemed to be the value in
use for the purposes of performing an impairment test of goodwill, unless this would lead to an impairment loss. If goodwill would be impaired using
value in use as the recoverable amount, a fair value less costs to sell assessment would be performed as this may lead to a higher recoverable amount.
The group calculates the value in use using a discounted cash flow model. The future cash flows are adjusted for risks specific to the cash-generating
unit and are discounted using a pre-tax discount rate. The discount rate is derived from the group’s post-tax weighted average cost of capital and is
adjusted where applicable to take into account any specific risks relating to the country where the cash-generating unit is located. The rate to be
applied to each country is reassessed each year. Discount rates of 12% and 14% have been used for goodwill impairment calculations performed in
2013 (2012 12% and 14%).
The business segment plans, which are approved on an annual basis by senior management, are the primary source of information for the
determination of value in use. They contain forecasts for oil and natural gas production, refinery throughputs, sales volumes for various types of refined
products (e.g. gasoline and lubricants), revenues, costs and capital expenditure. As an initial step in the preparation of these plans, various
environmental assumptions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates, are set by senior
management. These environmental assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other
macroeconomic factors and historical trends and variability.
Upstream
Goodwill
Excess of recoverable amount over carrying amount
2013
7,812
6,811
$ million
2012
7,862
25,871
The table above shows the carrying amount of the goodwill for the segment and the excess of the recoverable amount, based upon a value in use
calculation, over the carrying amount (the headroom).
The value in use is based on the cash flows expected to be generated by the projected oil or natural gas production profiles up to the expected dates of
cessation of production of each producing field, based on current estimates of reserves. As the production profile and related cash flows can be
estimated from BP’s past experience, management believes that the cash flows generated over the estimated life of field is the appropriate basis upon
which to assess goodwill and individual assets for impairment. The date of cessation of production depends on the interaction of a number of variables,
such as the recoverable quantities of hydrocarbons, the production profile of the hydrocarbons, the cost of the development of the infrastructure
necessary to recover the hydrocarbons, the production costs, the contractual duration of the production concession and the selling price of the
hydrocarbons produced. As each producing field has specific reservoir characteristics and economic circumstances, the cash flows of the fields are
computed using appropriate individual economic models and key assumptions agreed by BP’s management. Capital expenditure, operating costs and
expected hydrocarbon production profiles up to 2023 are derived from the business segment plan. Estimated production volumes and cash flows up to
the date of cessation of production on a field-by-field basis are developed to be consistent with this. The production profiles used are consistent with
the reserve volumes approved as part of BP’s centrally controlled process for the estimation of proved and probable reserves and total resources.
BP Annual Report and Form 20-F 2013
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Intangible assets are deemed to have a recoverable amount equal to their carrying amount. Consistent with prior years, the 2013 review for impairment
was carried out during the fourth quarter.
The Brent oil price and Henry Hub natural gas price assumptions used in the impairment review of goodwill are shown in the table below.
Brent oil price ($/bbl)
Henry Hub natural gas price ($/mmBtu)
Brent oil price ($/bbl)
Henry Hub natural gas price ($/mmBtu)
2014
108
3.86
2013
105
3.96
2015
102
4.02
2014
100
4.25
2016
97
4.10
2015
96
4.42
2017
93
4.17
2016
93
4.61
2013
2019 and
thereafter
90
6.50
2012
2018 and
thereafter
90
6.50
2018
90
4.27
2017
91
4.82
Key assumptions for oil and gas prices for the first five years were derived from forward price curves in the fourth quarter. Prices in 2019 and beyond
were determined using long-term views of global supply and demand, building upon past experience of the industry and using information from
external sources. These prices were adjusted to arrive at appropriate consistent price assumptions for different qualities of oil and gas, or where
appropriate, contracted oil and gas prices were applied.
The key assumptions required for the value-in-use estimation are the oil and natural gas prices, production volumes and the discount rate. The
sensitivity of the headroom to changes in the key assumptions was estimated. Due to the non-linear relationship of different variables, the calculations
were performed using a number of simplifying assumptions, including assuming a change to the variable being tested only, therefore a detailed
calculation at any given price may produce a different result.
It is estimated that if the oil price assumption for all future years was approximately equal to the current assumption for 2019 and beyond, this would
cause the recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment. It is estimated that if the
price assumption for natural gas was around 24% lower than the current assumption for 2019 and beyond the headroom would be reduced to zero.
Estimated production volumes are based on detailed data for each field and take into account development plans agreed by management as part of the
long-term planning process. The average production for the purposes of goodwill impairment testing over the next 15 years is 597mmboe per year
(2012 576mmboe per year). It is estimated that if this production volume were to be reduced by around 2% for the whole period, this would cause the
recoverable amount to be equal to the carrying amount of goodwill and related non-current assets of the segment.
It is estimated that if the discount rate was approximately 14% for the entire portfolio this would cause the recoverable amount to be equal to the
carrying amount of goodwill and related non-current assets of the segment.
Downstream
Goodwill
Excess of recoverable amount over carrying amount
Rhine FVC
Lubricants
Other
643
2,759
3,518
n/a
116
n/a
2013
Total
4,277
n/a
Rhine FVC
Lubricants
Other
627
2,411
3,441
n/a
100
n/a
$ million
2012
Total
4,168
n/a
Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of two to five years. To determine the
value in use for each of the cash-generating units, cash flows for a period of 10 years are discounted and aggregated with a terminal value.
Rhine FVC
The key assumptions to which the calculation of value in use for the Rhine FVC is most sensitive are refinery gross margins, throughput volumes and
discount rate. Gross margin assumptions used in the Rhine FVC plan are consistent with those used to develop the regional Refining Marker Margin
(RMM). The average values assigned to the regional RMM and refinery throughput volume over the plan period are $12.35 per barrel and
250mmbbl per year (2012 $12.30 per barrel and 246mmbbl per year). These values reflect past experience and are consistent with external sources.
Cash flows beyond the five-year plan period are extrapolated using a nominal 4% growth rate (2012 4%).
No reasonably possible change in the discount rate would cause the Rhine FVC unit’s carrying amount to exceed its recoverable amount. It is
estimated that if the refinery margin assumption was $1.9 per barrel lower than the current assumption, the recoverable amount would equal the
carrying amount. It is also estimated that if the refinery throughput volume assumption was 32mmbbl per year lower than the current assumption, the
recoverable amount would equal the carrying amount.
Lubricants
In certain circumstances IAS 36 allows the use of the most recent detailed calculations of the recoverable amount performed in an earlier period as the
basis for the current year’s goodwill impairment test. The most recent detailed calculation of the Lubricants unit’s recoverable amount was performed
in 2009 and this was used as the basis for the tests in 2010-2012 as the criteria of IAS 36 were met in each of those years. IAS 36 does not specify for
how many years such an approach is appropriate and management determined that a re-performance of the test was appropriate in 2013 given the
passage of time since 2009. There was no significant change in the outcome of this test compared to that in 2009.
The key assumptions to which the calculation of the value in use for the Lubricants unit is most sensitive are operating margins, sales volumes, and
discount rate. Operating margin and sales volumes assumptions used in the detailed impairment review of goodwill calculation are consistent with the
assumptions used in the Lubricant unit’s business plan and values assigned to these key assumptions reflect past experience. No reasonably possible
change in any of these key assumptions would cause the unit’s carrying amount to exceed its recoverable amount. Cash flows beyond the plan period
are extrapolated using a 3% growth rate (2009 3%).
162
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16. Intangible assets
Cost
At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers
Reclassified as assets held for sale
Deletions
At 31 December
Amortization
At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Transfers
Reclassified as assets held for sale
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
17. Investments in joint ventures
Exploration
and appraisal
expenditure
Other
intangibles
Exploration
and appraisal
expenditure
Other
intangibles
2013
Total
28,250
(5)
–
4,800
(4,365)
–
(3,002)
25,678
3,618
(2)
2,977
338
–
(365)
–
(2,927)
3,639
3,739
(5)
–
336
–
–
(134)
3,936
2,541
(2)
267
85
–
–
–
(129)
2,762
21,216
–
(68)
5,244
(1,306)
(67)
(508)
24,511
783
–
745
–
(42)
–
–
(409)
1,077
23,434
20,433
24,511
–
–
4,464
(4,365)
–
(2,868)
21,742
1,077
–
2,710
253
–
(365)
–
(2,798)
877
20,865
23,434
$ million
2012
Total
24,716
50
12
5,587
(1,306)
(93)
(716)
28,250
3,063
25
1,062
126
(42)
–
(21)
(595)
3,618
3,500
50
80
343
–
(26)
(208)
3,739
2,280
25
317
126
–
–
(21)
(186)
2,541
1,174
22,039
1,198
24,632
1,198
24,632
1,220
21,653
The significant joint ventures of the BP group at 31 December 2013 are shown in Note 38. Summarized financial information for the group’s share of
joint ventures is shown below. Balance sheet information shown below excludes data relating to joint ventures classified as assets held for sale as at
the end of the period. Income statement information shown below includes data relating to joint ventures reclassified as assets held for sale during the
period up until the date of reclassification. The group does not have any individually material joint ventures.
The following table provides aggregated summarized financial information relating to the group’s share of joint ventures.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Profit for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Group investment in joint ventures
Group share of net assets (as above)
Loans made by group companies to joint ventures
$ million
2011
11,993
1,315
115
1,200
433
767
–
767
2013
2012
12,507
12,507
1,076
130
946
499
447
38
485
11,576
3,095
14,671
2,276
3,499
5,775
8,896
8,896
303
9,199
778
113
665
405
260
(52)
208
11,147
2,931
14,078
2,350
3,379
5,729
8,349
8,349
265
8,614
BP Annual Report and Form 20-F 2013
163
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17. Investments in joint ventures – continued
Transactions between the group and its joint ventures are summarized below.
Sales to joint ventures
Product
LNG, crude oil and oil products, natural gas, employee services
Sales
4,125
Purchases from joint ventures
Product
Purchases
LNG, crude oil and oil products, natural gas, refinery operating
2013
Amount
receivable at
31 December
342
2013
Amount
payable at
31 December
2012
Amount
receivable at
31 December
379
2012
Amount
payable at
31 December
Sales
4,272
Purchases
Sales
3,196
Purchases
$ million
2011
Amount
receivable at
31 December
423
$ million
2011
Amount
payable at
31 December
costs, plant processing fees
503
51
1,107
116
1,165
62
The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be settled in
cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in
respect of bad or doubtful debts. Dividends receivable are not included in the table above.
BP has commitments amounting to $21 million (2012 $53 million) in relation to contracts with joint ventures for the purchase of LNG, crude oil and oil
products, refinery operating costs and storage and handling services. See Note 36 for further information on capital commitments relating to BP’s
investments in joint ventures.
18. Investments in associates
The following table provides aggregated financial information for the group’s associates as it relates to the amounts recognized in the group income
statement and on the group balance sheet.
Rosneft
TNK-BP
Other associates
Earnings from associates –
after interest and tax
2013
2,058
–
684
2,742
2012
–
2,986
689
3,675
2011
–
4,185
731
4,916
2013
13,681
–
2,955
16,636
2012
–
–
2,998
2,998
$ million
Investments
in associates
2011
–
10,013
3,278
13,291
The associate that is material to the group at 31 December 2013 is Rosneft (2012 TNK-BP). In 2013, BP concluded transactions to sell its 50% interest
in TNK-BP to Rosneft and to increase BP’s investment in Rosneft. BP and Rosneft announced heads of terms for this transaction on 22 October 2012,
after which our investment in TNK-BP was classified as an asset held for sale and therefore equity accounting ceased. See below and Note 6 for
further information. Other significant associates of the BP group at 31 December 2013 are shown in Note 38.
At 31 December 2013, and since the transaction described in Note 6 concluded on 21 March 2013, BP owned 19.75% of the voting shares of OJSC
Oil Company Rosneft (Rosneft), a Russian oil and gas company. Rosneft shares are listed on the MICEX stock exchange in Moscow and its global
depository receipts are listed on the London Stock Exchange. The Russian federal government, through its investment company OJSC Rosneftegaz,
owned 69.5% of the voting shares of Rosneft at 31 December 2013.
BP uses the equity method of accounting for its investment in Rosneft because in management’s judgement BP has significant influence over Rosneft,
see Note 1 – Interests in other entities – significant estimate or judgement for further information.
164
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18. Investments in associates – continued
The following table provides summarized financial information at 100% share relating to each of the group’s material associates.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Non-controlling interests
Profit for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Non-controlling interests
$ million
Gross amount
2013
2012
2011
Rosneft
TNK-BPa
TNK-BP
60,200
11,984
264
11,720
2,666
684
8,370
(77)
8,293
122,866
49,350
8,810
168
8,642
1,958
712
5,972
26
5,998
14,106
1,337
12,769
2,137
213
10,419
(441)
9,978
149,149
48,775
197,924
43,175
83,458
126,633
2,020
69,271
a BP ceased equity accounting for TNK-BP on 22 October 2012. See Note 6 for further information.
The group received dividends of $456 million from Rosneft in 2013, net of withholding tax (2012 dividends of $709 million from TNK-BP and 2011
dividends of $3,747 million from TNK-BP).
Summarized financial information for the group’s share of associates is shown below. Balance sheet information shown below does not include data
relating to associates classified as assets held for sale as at the end of the period. Income statement and other comprehensive income information
shown below includes data relating to associates classified as assets held for sale during the period prior to their classification as assets held for sale.
Sales and other operating revenues
24,266
7,967
32,233
24,675
11,965
36,640
30,100
12,145
42,245
Rosnefta
Other
2013
Total
TNK-BPb
Other
2012
Total
TNK-BP
Other
$ million
BP share
2011
Total
F
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Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Non-controlling interests
Profit for the year
Other comprehensive income
Total comprehensive income
Non-current assets
Current assets
Total assets
Current liabilities
Non-current liabilities
Total liabilities
Non-controlling interests
2,786
264
2,522
422
42
2,058
(87)
1,971
29,457
9,633
39,090
8,527
16,483
25,010
399
13,681
908
11
897
213
–
684
2
686
3,148
2,477
5,625
2,114
1,053
3,167
–
2,458
3,694
275
3,419
635
42
2,742
(85)
4,405
84
4,321
979
356
2,986
13
2,657
2,999
32,605
12,110
44,715
10,641
17,536
28,177
399
16,139
Group investment in associates
Group share of net assets (as above)
Loans made by group companies
to associates
13,681
2,458
16,139
–
497
497
13,681
2,955
16,636
–
–
–
–
–
–
–
–
–
–
–
5,992
132
5,860
1,333
342
4,185
(39)
4,146
958
13
945
214
–
731
–
731
6,950
145
6,805
1,547
342
4,916
(39)
4,877
906
16
890
201
–
689
(6)
683
3,270
2,399
5,669
2,126
1,290
3,416
–
2,253
5,311
100
5,211
1,180
356
3,675
7
3,682
3,270
2,399
5,669
2,126
1,290
3,416
–
2,253
2,253
2,253
745
2,998
745
2,998
a The fair value of BP’s 19.75% stake in Rosneft was $15,937 million at 31 December 2013 based on the quoted market share price of $7.62 per share.
b BP ceased equity accounting for TNK-BP on 22 October 2012. See Note 6 for further information.
BP Annual Report and Form 20-F 2013
165
18. Investments in associates – continued
Transactions between the group and its associates are summarized below.
Sales to associates
Product
LNG, crude oil and oil products, natural gas, employee services
Purchases from associates
Product
Crude oil and oil products, natural gas, transportation tariff
2013
Amount
receivable at
31 December
783
2013
Amount
payable at
31 December
2012
Amount
receivable at
31 December
401
2012
Amount
payable at
31 December
Sales
3,771
Purchases
Sales
3,855
Purchases
$ million
2011
Amount
receivable at
31 December
393
$ million
2011
Amount
payable at
31 December
3,470
9,135
932
8,159
815
Sales
5,170
Purchases
21,205
The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in cash.
There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income statement in
respect of bad or doubtful debts. Dividends receivable are not included in the table above.
The majority of the purchases from associates are crude oil and oil products purchased from Rosneft. BP has commitments amounting to $6,077
million (2012 $595 million) in relation to contracts with its associates for the purchase of crude oil and oil products, transportation and storage. See
Note 36 for further information on capital commitments relating to BP’s investments in associates.
19. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.
At 31 December 2013
Financial assets
Other investments – equity shares
– other
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
At 31 December 2012
Financial assets
Other investments – equity shares
– other
Loans
Trade and other receivables
Derivative financial instruments
Cash and cash equivalents
Financial liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Note
Loans and
receivables
Available-
for-sale financial
assets
Held-to-
maturity
investments
At fair value
through profit
or loss
Derivative
hedging
instruments
Financial
liabilities
measured at
amortized cost
$ million
Total carrying
amount
20
20
22
26
23
25
26
27
20
20
22
26
23
25
26
27
–
–
979
39,630
–
19,153
–
–
–
–
291
1,167
–
–
–
2,267
–
–
–
–
–
–
–
–
–
1,100
–
–
–
–
59,762
3,725
1,100
–
–
889
35,962
–
15,128
–
–
–
–
1,433
1,005
–
–
–
4,507
–
–
–
–
51,979
6,945
–
–
–
–
–
–
–
–
–
–
–
–
574
–
–
5,189
–
–
(4,159)
–
–
1,604
–
585
–
–
5,342
–
–
(5,093)
–
–
834
–
–
–
–
995
–
–
(388)
–
–
607
–
–
–
–
3,459
–
–
(288)
–
–
3,171
–
–
–
–
–
–
(48,072)
–
(9,507)
(48,192)
(105,771)
–
–
–
–
–
–
(44,405)
–
(7,366)
(48,168)
(99,939)
291
1,741
979
39,630
6,184
22,520
(48,072)
(4,547)
(9,507)
(48,192)
(38,973)
1,433
1,590
889
35,962
8,801
19,635
(44,405)
(5,381)
(7,366)
(48,168)
(37,010)
The fair value of finance debt is shown in Note 27. For all other financial instruments, the carrying amount is either the fair value, or approximates the
fair value.
Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments
including: market risks relating to commodity prices, foreign currency exchange rates, interest rates and equity prices; credit risk; and liquidity risk.
166
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19. Financial instruments and financial risk factors – continued
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The GFRC is
chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax and the integrated
supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk governance framework for
the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to the board, that the group’s financial
risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified, measured and managed in accordance with
group policies and group risk appetite.
The group’s trading activities in the oil, natural gas and power markets are managed within the integrated supply and trading function, while the
activities in the financial markets are managed by the treasury function, working under the compliance and control structure of the integrated supply
and trading function. All derivative activity is carried out by specialist teams that have the appropriate skills, experience and supervision. These teams
are subject to close financial and management control.
The integrated supply and trading function maintains formal governance processes that provide oversight of market risk associated with trading activity.
A policy and risk committee monitors and validates limits and risk exposures, reviews incidents and validates risk-related policies, methodologies and
procedures. A commitments committee approves value-at-risk delegations, the trading of new products, instruments and strategies and material
commitments.
In addition, the integrated supply and trading function undertakes derivative activity for risk management purposes under a separate control framework
as described more fully below.
(a) Market risk
Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of a business. The
primary commodity price risks that the group is exposed to include oil, natural gas and power prices that could adversely affect the value of the group’s
financial assets, liabilities or expected future cash flows. The group enters into derivatives in a well-established entrepreneurial trading operation. In
addition, the group has developed a control framework aimed at managing the volatility inherent in certain of its natural business exposures. In
accordance with the control framework the group enters into various transactions using derivatives for risk management purposes.
The major components of market risk are commodity price risk, foreign currency exchange risk, interest rate risk and equity price risk, each of which is
discussed below.
(i) Commodity price risk
The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes available in the related
commodity markets. Oil and natural gas swaps, options and futures are used to mitigate price risk. Power trading is undertaken using a combination of
over-the-counter forward contracts and other derivative contracts, including options and futures. This activity is on both a standalone basis and in
conjunction with gas derivatives in relation to gas-generated power margin. In addition, NGLs are traded around certain US inventory locations using
over-the-counter forward contracts in conjunction with over-the-counter swaps, options and physical inventories.
The group measures market risk exposure arising from its trading positions using value-at-risk techniques. These techniques make a statistical
assessment of the market risk arising from possible future changes in market prices over a one-day holding period. The value-at-risk measure is
supplemented by stress testing. Value-at-risk limits are in place for each trading activity and for the group’s trading activity in total. The board has
delegated a limit of $100 million value at risk in support of this trading activity.
In addition, the group has embedded derivatives relating to certain natural gas contracts. The net fair value of these contracts was a liability of $652
million at 31 December 2013 (2012 liability of $1,112 million). For these embedded derivatives the sensitivity of the net fair value to an immediate 10%
favourable or adverse change in each key assumption is less than $100 million in each case.
(ii) Foreign currency exchange risk
Where the group enters into foreign currency exchange contracts for entrepreneurial trading purposes the activity is controlled using trading value-at-
risk techniques as explained above.
Since BP has global operations, fluctuations in foreign currency exchange rates can have a significant effect 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 translation 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 currency exchange management policy is to limit
economic and material transactional exposures arising from currency movements against the US dollar. The group co-ordinates the handling of foreign
currency exchange risks centrally, by netting off naturally-occurring opposite exposures wherever possible, and then managing any material residual
foreign currency exchange risks.
The group manages these exposures by constantly reviewing the foreign currency economic value at risk and aims to manage such risk to keep the
12-month foreign currency value at risk below $400 million. At no point over the past three years did the value at risk exceed the maximum risk limit.
The most significant exposures relate to capital expenditure commitments and other UK and European operational requirements, for which a hedging
programme is in place and hedge accounting is claimed as outlined in Note 26.
For highly probable forecast capital expenditures the group locks in the US dollar cost of non-US dollar supplies by using currency forwards and futures.
The main exposures are sterling, euro, Norwegian krone, Australian dollar and Korean won. At 31 December 2013 the most significant open contracts
in place were for $723 million sterling (2012 $853 million sterling).
For other UK, European and Australian operational requirements the group uses cylinders (purchased call and sold put options) and currency forwards
to manage the estimated exposures on a 12-month rolling basis. At 31 December 2013, the open positions relating to cylinders consisted of receive
sterling, pay US dollar cylinders for $2,770 million (2012 $2,886 million); receive euro, pay US dollar cylinders for $962 million (2012 $1,636 million);
receive Australian dollar, pay US dollar cylinders for $401 million (2012 $522 million).
In addition, most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2013, the total foreign
currency net borrowings not swapped into US dollars amounted to $665 million (2012 $364 million).
(iii) Interest rate risk
Where the group enters into money market contracts for entrepreneurial trading purposes the activity is controlled using value-at-risk techniques as
described above.
BP Annual Report and Form 20-F 2013
167
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BP is also exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows or the fair values of its financial
instruments, principally finance debt. While the group issues debt in a variety of currencies based on market opportunities, it uses derivatives to swap
the debt to a floating rate exposure, mainly to US dollar floating, but in certain defined circumstances maintains a US dollar fixed rate exposure for a
proportion of debt. The proportion of floating rate debt net of interest rate swaps at 31 December 2013 was 65% of total finance debt outstanding
(2012 65%). The weighted average interest rate on finance debt at 31 December 2013 was 2% (2012 2%) and the weighted average maturity of fixed
rate debt was four years (2012 four years).
The group’s earnings are sensitive to changes in interest rates on the floating rate element of the group’s finance debt. If the interest rates applicable
to floating rate instruments were to have increased by one percentage point on 1 January 2014, it is estimated that the group’s finance costs for 2014
would increase by approximately $312 million (2012 $311 million increase in 2013).
(iv) Equity price risk
The group holds equity investments, typically for strategic purposes, that are classified as non-current available-for-sale financial assets and are
measured initially at fair value with changes in fair value recognized in other comprehensive income.
At 31 December 2013 the group had no significant exposure to the price of quoted equity instruments. At 31 December 2012, an increase or decrease
of 10% in quoted equity prices would have resulted in an immediate credit or charge to other comprehensive income of $1,502 million. At
31 December 2012, 82% of the carrying amount of non-current available-for-sale equity financial assets represented the group’s 1.25% stake in
Rosneft, thus the group’s exposure was concentrated on changes in the share price of this equity in particular. The sensitivity analysis at 31 December
2012 includes the impact of a change in the share price on the valuation of the contracts to acquire Rosneft shares accounted for as cash flow hedge
derivatives.
(b) Credit risk
Credit risk is the risk that a customer or counterparty to a financial instrument will fail to perform or fail to pay amounts due causing financial loss to the
group and arises from cash and cash equivalents, derivative financial instruments and deposits with financial institutions and principally from credit
exposures to customers relating to outstanding receivables. Credit exposure also exists in relation to guarantees issued by group companies under
which amounts outstanding at 31 December 2013 were $199 million (2012 $237 million) in respect of liabilities of joint ventures and associates and
$305 million (2012 $717 million) in respect of liabilities of other third parties.
The group has a credit policy, approved by the CFO, that is designed to ensure that consistent processes are in place throughout the group to measure
and control credit risk. Credit risk is considered as part of the risk-reward balance of doing business. On entering into any business contract the extent
to which the arrangement exposes the group to credit risk is considered. Key requirements of the policy include segregation of credit approval
authorities from any sales, marketing or trading teams authorized to incur credit risk; the establishment of credit systems and processes to ensure that
all counterparty exposure is rated and that all counterparty exposure and limits can be monitored and reported; and the timely identification and
reporting of any non-approved credit exposures and credit losses. While each segment of the group is typically responsible for its own credit risk
management and reporting consistent with group policy, the treasury function holds group-wide credit risk authority and oversight responsibility for
exposure to banks and financial institutions.
The maximum credit exposure associated with financial assets is equal to the carrying amount. The group does not aim to remove credit risk entirely
but expects to experience a certain level of credit losses. As at 31 December 2013, the group had in place credit enhancements designed to mitigate
approximately $13 billion of credit risk (2012 $12 billion). Reports are regularly prepared and presented to the GFRC that cover the group’s overall credit
exposure and expected loss trends, exposure by segment, and overall quality of the portfolio.
For the contracts comprising derivative financial instruments in an asset position at 31 December 2013 it is estimated that over 80% (2012 over 70%,
excluding the contracts with Rosneft accounted for as derivatives) of the unmitigated credit exposure is to counterparties of investment grade credit
quality.
For cash and cash equivalents, the treasury function dynamically manages bank deposit limits to ensure cash is well-diversified and to reduce
concentration risks. At 31 December 2013, 92% of the cash and cash equivalents balance was deposited with financial institutions rated at least A- by
Standard & Poor’s and Fitch, and A3 by Moody’s. Of the total cash and cash equivalents held at year end, collateral of $5,450 million was held by
third-party custodians in tri-partite repurchase agreements, which would only be released to BP in the event of repayment default by the borrower.
Trade and other receivables of the group are analysed in the table below. By comparing the BP credit ratings to the equivalent external credit ratings, it
is estimated that approximately 70-80% (2012 approximately 70-80%) of the unmitigated trade receivables portfolio exposure is of investment grade
credit quality. Current assets, including trade and other receivables, in Egypt amount to $2.3 billion (see page 241), of which over one third relates to
trade receivables which are not impaired but are past the original due date. Management is working with the counterparties to continue to collect these
amounts.
Trade and other receivables at 31 December
Neither impaired nor past due
Impaired (net of provision)
Not impaired and past due in the following periods
within 30 days
31 to 60 days
61 to 90 days
over 90 days
2013
37,201
27
1,054
249
216
883
$ million
2012
33,053
80
1,337
286
225
981
39,630
35,962
Movements in the impairment provision for trade receivables are shown in Note 24.
Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements
The following table shows the gross amounts of recognized financial assets and liabilities (i.e. before offsetting) and the amounts offset in the balance
sheet. Financial assets and liabilities are only offset when the group currently has a legally enforceable right to set off the recognized amounts and the
group intends to either settle on a net basis or realize the asset and settle the liability simultaneously. A right of set off is the group’s legal right to
settle an amount payable to a creditor by applying against it an amount receivable from the same counterparty. The relevant legal jurisdiction and laws
applicable to the relationships between the parties need to be considered when assessing whether a current legally enforceable right to set off exists.
168
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19. Financial instruments and financial risk factors – continued
Furthermore, amounts which cannot be offset under IFRS, but which could be settled net under the terms of master netting agreements if certain
conditions arise, and collateral received or pledged, are also shown in the table to show the total net exposure of the group.
At 31 December 2013
Derivative assets
Derivative liabilities
Trade receivables
Trade payables
At 31 December 2012
Derivative assets
Derivative liabilities
Trade receivables
Trade payables
Gross
amounts of
recognized
financial
assets
(liabilities)
7,271
(5,457)
11,034
(10,619)
9,291
(6,117)
8,829
(9,330)
Amounts
set off
(1,563)
1,563
(7,744)
7,744
(1,870)
1,870
(6,368)
6,368
Related amounts not set off
in the balance sheet
Net amounts
presented on
the balance
sheet
Master
netting
arrangements
Cash
collateral
(received)
pledged
5,708
(3,894)
3,290
(2,875)
7,421
(4,247)
2,461
(2,962)
(344)
344
(1,287)
1,287
(754)
754
(578)
578
(231)
–
(264)
–
(175)
–
(176)
–
$ million
Net amount
5,133
(3,550)
1,739
(1,588)
6,492
(3,493)
1,707
(2,384)
(c) Liquidity risk
Liquidity risk is the risk that suitable sources of funding for the group’s business activities may not be available. The group’s liquidity is managed
centrally with operating units forecasting their cash and currency requirements to the central treasury function. Unless restricted by local regulations,
subsidiaries pool their cash surpluses to treasury, which will then arrange to fund other subsidiaries’ requirements, or invest any net surplus in the
market or arrange for necessary external borrowings, while managing the group’s overall net currency positions.
The group has in place a European Debt Issuance Programme (DIP) under which the group may raise up to $30 billion of debt for maturities of one
month or longer. At 31 December 2013, the amount drawn down against the DIP was $13,854 million (2012 $14,043 million). Since 5 February 2013,
the group has had a US shelf registration with a limit of $30 billion. This was converted from an unlimited shelf registration following the approval in
December 2012 of the settlement with the US Securities and Exchange Commission in respect of Gulf of Mexico oil spill related claims. Amounts
drawn down since conversion total $6.9 billion. In addition, the group has an Australian Note Issuance Programme of A$5 billion, and as at
31 December 2013 the amount drawn down was A$800 million (2012 A$500 million).
The group’s long-term credit ratings are A (positive outlook) from Standard & Poor’s, and A2 (stable outlook) from Moody’s Investor Services, both
remaining unchanged during 2013.
During 2013, $8.6 billion of long-term taxable bonds were issued with terms ranging from 18 months to 10 years. Commercial paper is issued at
competitive rates to meet short-term borrowing requirements as and when needed.
As a further liquidity measure, the group continues to maintain suitable levels of cash and cash equivalents, amounting to $22.5 billion at 31 December
2013, primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice (2012 $19.6 billion). At
31 December 2013, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,375 million of standby facilities, of
which $6,975 million is available to draw and repay until the first half of 2018, and $400 million is available to draw and repay until April 2016. These
facilities were renegotiated during 2013 with 26 international banks, and borrowings under them would be at pre-agreed rates.
The group also has committed letter of credit (LC) facilities totalling $7,475 million with a number of banks, allowing LCs to be issued for a maximum
one-year duration. There were also uncommitted secured LC facilities in place at 31 December 2013 for $2,410 million, which are secured against
inventories or receivables when utilized. The facilities only terminate by either party giving a stipulated termination notice to the other.
The amounts shown for finance debt in the table below include future minimum lease payments with respect to finance leases. The table also shows
the timing of cash outflows relating to trade and other payables and accruals.
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Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
Trade and
other
payables
43,790
1,007
822
761
1,405
207
80
48,072
Accruals
8,960
207
66
73
37
113
51
9,507
Finance
debt
7,381
6,630
6,720
5,828
5,279
15,933
421
48,192
2013
Interest
relating to
finance debt
885
752
621
498
388
809
119
4,072
Trade and
other
payables
42,512
903
434
373
71
79
33
44,405
Accruals
6,875
136
80
52
83
84
56
7,366
Finance
debt
9,401a
5,906
5,902
6,024
5,797
14,790
348
48,168
$ million
2012
Interest
relating to
finance debt
893
755
634
510
388
885
50
4,115
a In addition, current finance debt on the group balance sheet at 31 December 2012 included $632 million in respect of cash deposits received for disposals which completed in 2013.
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected maturities of
both derivative assets and liabilities as indicated in Note 26. Management does not currently anticipate any cash flows that could be of a significantly
different amount, or could occur earlier than the expected maturity analysis provided.
The table below shows cash outflows for derivative hedging instruments based upon contractual payment dates. The amounts reflect the maturity
profile of the fair value liability where the instruments will be settled net, and the gross settlement amount where the pay leg of a derivative will be
settled separately from the receive leg, as in the case of cross-currency swaps hedging non-US dollar finance debt. The swaps are with high
investment-grade counterparties and therefore the settlement-day risk exposure is considered to be negligible. Not shown in the table are the gross
BP Annual Report and Form 20-F 2013
169
19. Financial instruments and financial risk factors – continued
settlement amounts (inflows) for the receive leg of derivatives that are settled separately from the pay leg, which amount to $12,222 million at
31 December 2013 (2012 $8,620 million) to be received on the same day as the related cash outflows.
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
20. Other investments
Equity investments – listed
– unlisted
Repurchased gas pre-paid bonds
Contingent consideration
Other
2013
1,095
293
2,959
2,577
1,505
3,835
12,264
$ million
2012
1,356
1,107
295
1,261
2,577
1,903
8,499
$ million
2012
2013
Current
Non-current
Current
Non-current
–
–
276
186
5
467
3
288
408
292
574
1,565
–
–
303
–
16
319
1,182
251
686
–
585
2,704
At 31 December 2012 the group’s 1.25% stake in Rosneft was the most significant listed investment, with a fair value of $1,179 million.
BP entered into long-term gas supply contracts which are backed by gas pre-paid bonds. In 2010, BP was unsuccessful in the remarketing of these
bonds and repurchased them. The outstanding bonds associated with these long-term gas supply contracts held by BP are recorded within other
investments, with the related liability recorded within other payables on the balance sheet. The fair value of the gas pre-paid bonds is the same as the
carrying amount, as the bonds are based on floating rate interest with weekly market re-set, and as such are in level 1 of the fair value hierarchy.
At 31 December 2013 the group had contingent consideration receivable in respect of the disposal of the Devenick field, classified as an
available-for-sale financial asset.
Other non-current investments at 31 December 2013 include $574 million relating to life insurance policies (2012 $585 million). The life insurance
policies have been designated as financial assets at fair value through profit and loss and their valuation methodology is in level 3 of the fair value
hierarchy. Fair value losses of $4 million were recognized in the income statement (2012 $70 million gain and 2011 $21 million gain).
21. Inventories
Crude oil
Natural gas
Refined petroleum and petrochemical products
Supplies
Trading inventories
2013
10,190
235
15,427
25,852
2,735
28,587
644
29,231
$ million
2012
9,123
187
15,465
24,775
2,428
27,203
1,000
28,203
Cost of inventories expensed in the income statement
298,351
292,774
The inventory valuation at 31 December 2013 is stated net of a provision of $322 million (2012 $124 million) to write inventories down to their net
realizable value. The net charge to the income statement in the year in respect of inventory net realizable value provisions was $195 million
(2012 $28 million credit).
Trading inventories are valued using quoted benchmark bid prices adjusted as appropriate for location and quality differentials. As such they are
predominantly categorized within level 2 of the fair value hierarchy.
Inventories with a carrying amount of $227 million (2012 $64 million) have been pledged as security for certain of the group’s liabilities at
31 December 2013.
170
BP Annual Report and Form 20-F 2013
22. Trade and other receivables
Financial assets
Trade receivables
Amounts receivable from joint ventures and associates
Other receivables
Non-financial assets
Gulf of Mexico oil spill trust fund reimbursement asseta
Other receivables
2013
$ million
2012
Current
Non-current
Current
Non-current
28,868
1,213
6,594
36,675
2,457
699
3,156
39,831
183
47
2,725
2,955
2,442
588
3,030
5,985
26,485
871
5,683
33,039
4,178
394
4,572
37,611
151
102
2,670
2,923
2,264
774
3,038
5,961
a See Note 2 for further information.
Trade and other receivables are predominantly non-interest bearing. See Note 19 for further information.
Receivables with a carrying amount of $236 million (2012 $12 million) have been pledged as security for certain of the group’s liabilities at
31 December 2013.
23. Cash and cash equivalents
Cash at bank and in hand
Term bank deposits
Cash equivalents
2013
6,907
12,246
3,367
22,520
$ million
2012
5,885
9,243
4,507
19,635
Cash and cash equivalents comprise cash in hand; current balances with banks and similar institutions; term deposits of three months or less with
banks and similar institutions; money market funds and commercial paper. The carrying amounts of cash at bank and in hand and term bank deposits
approximate their fair values. Substantially all of the other cash equivalents are categorized within level 1 of the fair value hierarchy.
Cash and cash equivalents at 31 December 2013 includes $1,626 million (2012 $1,544 million) that is restricted. Included in restricted cash at
31 December 2012 was $709 million relating to the dividend received from TNK-BP in December 2012 which remained restricted until completion of
the sale of BP’s interest in TNK-BP to Rosneft, which occurred in the first quarter of 2013. See Note 6 for further information. The remaining restricted
cash balances relate largely to amounts required to cover initial margin on trading exchanges.
24. Valuation and qualifying accounts
At 1 January
Charged to costs and expenses
Charged to other accountsa
Deductions
At 31 December
a Principally currency transactions.
2013
2012
$ million
2011
Accounts
receivable
Fixed asset
investments
Accounts
receivable
Fixed asset
investments
Accounts
receivable
Fixed asset
investments
489
82
(4)
(224)
343
349
4
4
(189)
168
332
240
7
(90)
489
643
196
18
(508)
349
428
115
(16)
(195)
332
540
111
(3)
(5)
643
Valuation and qualifying accounts comprise impairment provisions for accounts receivable and fixed asset investments, and are deducted in the
balance sheet from the assets to which they apply.
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25. Trade and other payables
Financial liabilities
Trade payables
Amounts payable to joint ventures and associates
Other payables
Non-financial liabilities
Other payables
Trade and other payables are predominantly non-interest bearing. See Note 19 for further information.
2013
$ million
2012
Current
Non-current
Current
Non-current
28,926
3,576
11,288
43,790
3,369
47,159
–
47
4,235
4,282
474
4,756
29,920
1,105
11,487
42,512
4,161
46,673
–
102
1,791
1,893
399
2,292
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171
26. Derivative financial instruments
In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures in relation
to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating rate and fixed rate
debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives and policies pursued in
relation to those risks is set out in Note 19. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in
conjunction with these activities using a similar range of contracts.
The fair values of derivative financial instruments at 31 December are set out below.
Derivatives held for trading
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Embedded derivatives
Commodity price contracts
Cash flow hedges
Equity price derivatives
Currency forwards, futures and cylinders
Cross-currency interest rate swaps
Fair value hedges
Currency forwards, futures and swaps
Interest rate swaps
Of which – current
– non-current
Fair value
asset
2013
Fair value
liability
Fair value
asset
192
810
2,840
871
475
5,188
1
1
–
129
–
129
340
526
866
6,184
2,675
3,509
(111)
(806)
(2,029)
(560)
–
(3,506)
(653)
(653)
–
(30)
(69)
(99)
(154)
(135)
(289)
(4,547)
(2,322)
(2,225)
175
841
3,536
719
71
5,342
–
–
1,339
51
1
1,391
875
1,193
2,068
8,801
4,507
4,294
$ million
2012
Fair value
liability
(189)
(707)
(2,496)
(589)
–
(3,981)
(1,112)
(1,112)
–
(41)
–
(41)
(247)
–
(247)
(5,381)
(2,658)
(2,723)
Exchange traded derivatives are valued using closing prices provided by the exchange as at the balance sheet date. These derivatives are categorized
within level 1 of the fair value hierarchy. Over-the-counter (OTC) financial swaps and physical commodity sale and purchase contracts are generally
valued using readily available information in the public markets and quotations provided by brokers and price index developers. These quotes are
corroborated with market data and are categorized within level 2 of the fair value hierarchy.
In certain less liquid markets, or for longer-term contracts, forward prices are not as readily available. In these circumstances, OTC financial swaps and
physical commodity sale and purchase contracts are valued using internally developed methodologies that consider historical relationships between
various commodities, and that result in management’s best estimate of fair value. These contracts are categorized within level 3 of the fair value
hierarchy.
Financial OTC and physical commodity options are valued using industry standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and contractual prices for the underlying instruments, as well as other relevant economic factors.
The degree to which these inputs are observable in the forward markets determines whether the option is categorized within level 2 or level 3 of the
fair value hierarchy.
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to satisfy
supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original business objective,
and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are undertaken by using a range of
contract types in combination to create incremental gains by arbitraging prices between markets, locations and time periods. The net of these
exposures is monitored using market value-at-risk techniques as described in Note 19.
172
BP Annual Report and Form 20-F 2013
26. Derivative financial instruments – continued
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Derivative assets held for trading have the following fair values and maturities.
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Less than
1 year
143
694
1,034
528
102
2,501
Less than
1 year
169
656
1,532
327
71
2,755
1-2 years
2-3 years
3-4 years
4-5 years
–
78
526
202
–
806
21
23
334
81
93
552
–
13
192
22
147
374
–
2
154
8
66
230
1-2 years
2-3 years
3-4 years
4-5 years
6
109
711
188
–
1,014
–
38
418
114
–
570
–
21
259
62
–
342
–
12
144
19
–
175
$ million
2013
Total
192
810
2,840
871
475
5,188
$ million
2012
Total
175
841
3,536
719
71
5,342
Over
5 years
28
–
600
30
67
725
Over
5 years
–
5
472
9
–
486
At 31 December 2013 the group had contingent consideration receivable in respect of a business disposal. The sale agreement contained an
embedded derivative – the whole agreement has, consequently, been designated at fair value through profit or loss and shown within other derivatives
held for trading, and falls within level 3 of the fair value hierarchy. The valuation depends on refinery throughput and future margins. At 31 December
2012, other derivatives related to the anticipated transaction with Rosneft – see Cash flow hedges below for further information.
Derivative liabilities held for trading have the following fair values and maturities.
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Less than
1 year
(111)
(620)
(778)
(400)
(1,909)
Less than
1 year
(189)
(580)
(1,199)
(341)
(2,309)
1-2 years
2-3 years
3-4 years
4-5 years
–
(100)
(319)
(99)
(518)
–
(42)
(157)
(48)
(247)
–
(31)
(110)
(13)
(154)
–
(13)
(102)
–
(115)
1-2 years
2-3 years
3-4 years
4-5 years
–
(77)
(440)
(133)
(650)
–
(27)
(241)
(59)
(327)
–
(12)
(135)
(21)
(168)
–
(8)
(78)
(10)
(96)
$ million
2013
Total
(111)
(806)
(2,029)
(560)
(3,506)
$ million
2012
Total
(189)
(707)
(2,496)
(589)
(3,981)
Over
5 years
–
–
(563)
–
(563)
Over
5 years
–
(3)
(403)
(25)
(431)
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BP Annual Report and Form 20-F 2013
173
26. Derivative financial instruments – continued
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by methodology
of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Fair value of derivative assets
Level 1
Level 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 1
Level 2
Level 3
Less: netting by counterparty
Net fair value
Less than
1 year
100
3,118
389
3,607
(1,106)
2,501
(87)
(2,790)
(138)
(3,015)
1,106
(1,909)
592
Less than
1 year
187
3,766
302
4,255
(1,500)
2,755
(189)
(3,476)
(144)
(3,809)
1,500
(2,309)
446
1-2 years
2-3 years
3-4 years
4-5 years
–
981
183
1,164
(358)
806
–
(733)
(143)
(876)
358
(518)
288
–
399
252
651
(99)
552
–
(215)
(131)
(346)
99
(247)
305
–
83
291
374
–
374
–
(36)
(118)
(154)
–
(154)
220
–
20
210
230
–
230
–
(15)
(100)
(115)
–
(115)
115
1-2 years
2-3 years
3-4 years
4-5 years
6
1,088
184
1,278
(264)
1,014
–
(810)
(104)
(914)
264
(650)
364
–
520
137
657
(87)
570
–
(315)
(99)
(414)
87
(327)
243
–
216
136
352
(10)
342
–
(78)
(100)
(178)
10
(168)
174
–
46
136
182
(7)
175
–
(19)
(84)
(103)
7
(96)
79
$ million
2013
Total
100
4,631
2,020
6,751
(1,563)
5,188
(87)
(3,820)
(1,162)
(5,069)
1,563
(3,506)
1,682
$ million
2012
Total
193
5,646
1,373
7,212
(1,870)
5,342
(189)
(4,726)
(936)
(5,851)
1,870
(3,981)
1,361
Over
5 years
–
30
695
725
–
725
–
(31)
(532)
(563)
–
(563)
162
Over
5 years
–
10
478
488
(2)
486
–
(28)
(405)
(433)
2
(431)
55
Level 3 derivatives
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair value
hierarchy.
Oil
price
105
(47)
110
–
(143)
(43)
–
(18)
Natural gas
price
Power
price
304
62
1
–
(52)
(1)
(1)
313
(43)
81
–
–
10
36
2
86
$ million
Total
437
96
111
475
(256)
(8)
1
856
Other
71
–
–
475
(71)
–
–
475
Net fair value of contracts at 1 January 2013
Gains (losses) recognized in the income statement
Purchases
New contracts
Settlements
Transfers out of level 3
Exchange adjustments
Net fair value of contracts at 31 December 2013
174
BP Annual Report and Form 20-F 2013
26. Derivative financial instruments – continued
Net fair value of contracts at 1 January 2012
Gains (losses) recognized in the income statement
New contracts
Settlements
Transfers into level 3
Transfers out of level 3
Exchange adjustments
Net fair value of contracts at 31 December 2012
Oil
price
162
30
–
(87)
–
–
–
105
Natural gas
price
Power
price
Other
408
4
–
(56)
(19)
(33)
–
304
13
(4)
–
–
–
(51)
(1)
(43)
–
–
71
–
–
–
–
71
$ million
Total
583
30
71
(143)
(19)
(84)
(1)
437
US natural gas price derivatives are valued using observable market data for maturities up to 60 months in basis locations that trade at a premium or
discount to the NYMEX Henry Hub price, and using internally developed price curves based on economic forecasts for periods beyond that time. At
31 December 2013, the US natural gas derivatives in level 3 of the fair value hierarchy had a net fair value of $351 million. Of this amount, $71 million
(asset of $598 million and liability of $527 million) depends on level 3 inputs, with the remainder valued using level 2 inputs. The significant
unobservable inputs for fair value measurements categorized within level 3 of the fair value hierarchy for the year ended 31 December 2013 are
presented below.
Natural gas price contracts
Unobservable inputs
Range
$/mmBtu
Weighted average
$/mmBtu
Long-dated market price
3.15-6.71
4.63
If the natural gas prices after 2018 were 10% higher (lower), this would result in a decrease (increase) in derivative assets of $82 million, and decrease
(increase) in derivative liabilities of $78 million, and a net decrease (increase) in profit before tax of $4 million.
Derivative gains and losses
Gains and losses relating to derivative contracts are included within sales and other operating revenues and within purchases in the income statement
depending upon the nature of the activity and type of contract involved. The contract types treated in this way include futures, options, swaps and
certain forward sales and forward purchases contracts, and relate to both currency and commodity trading activities. Gains or losses arise on contracts
entered into for risk management purposes, optimization activity and entrepreneurial trading. They also arise on certain contracts that are for normal
procurement or sales activity for the group but that are required to be fair valued under accounting standards. Also included within sales and other
operating revenues are gains and losses on inventory held for trading purposes. The total amount relating to all these items (excluding gains and losses
on realized physical derivative contracts that have been reflected gross in the income statement within sales and purchases) was a gain of $587 million
(2012 $411 million net loss and 2011 $216 million net gaina).
a The comparative amounts for 2012 and 2011 have been amended and now reflect only the margin on derivative contracts that have been reflected net within the income statement.
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Embedded derivatives
The group is a party to contracts containing embedded derivatives, the majority of which relate to certain natural gas contracts. Prior to the
development of an active gas trading market, UK gas contracts were priced using a basket of available price indices, primarily relating to oil products,
power and inflation. After the development of an active UK gas market, certain contracts were entered into or renegotiated using pricing formulae not
directly related to gas prices, for example, oil product and power prices. In these circumstances, pricing formulae have been determined to be
derivatives, embedded within the overall contractual arrangements that are not clearly and closely related to the underlying commodity. The resulting
fair value relating to these contracts is recognized on the balance sheet with gains or losses recognized in the income statement.
Key information on the natural gas contracts is given below.
At 31 December
Remaining contract terms
Contractual/notional amount
1 year and 5 months to 4 years and 9 months
153 million therms
2 years and 5 months to 5 years and 9 months
117 million therms
2013
2012
The commodity price embedded derivatives relate to natural gas contracts and are categorized in levels 2 and 3 of the fair value hierarchy. The
contracts in level 2 are valued using inputs that include price curves for each of the different products that are built up from active market pricing data.
Where necessary, the price curves are extrapolated to the expiry of the contracts (the last of which is in 2018) using all available external pricing
information; additionally, where limited data exists for certain products, prices are interpolated using historic and long-term pricing relationships. These
valuations are categorized in level 3. Transfers from level 3 to level 2 occur when the valuation no longer depends significantly on extrapolated or
interpolated data. Valuations use observable market data for maturities up to 36 months, and internally developed price curves based on economic
forecasts for periods beyond that time.
The following table shows the changes during the year in the net fair value of embedded derivatives, within level 3 of the fair value hierarchy.
Net fair value of contracts at 1 January
Settlements
Gains (losses) recognized in the income statement
Transfers out of level 3
Exchange adjustments
Net fair value of contracts at 31 December
2013
$ million
2012
Commodity
price
Commodity
price
(1,112)
316
142
258
17
(379)
(1,417)
375
(6)
–
(64)
(1,112)
BP Annual Report and Form 20-F 2013
175
26. Derivative financial instruments – continued
The fair value gain (loss) on embedded derivatives is shown below.
Commodity price embedded derivatives
Other embedded derivatives
Fair value gain (loss)
2013
459
–
459
2012
347
–
347
$ million
2011
190
(122)
68
Cash flow hedges
At 31 December 2013, the group held currency forwards and futures contracts and cylinders that were being used to hedge the foreign currency risk of
highly probable forecast transactions. Note 19 outlines the management of risk aspects for currency risk. For cash flow hedges the group only claims
hedge accounting for the intrinsic value on the currency with any fair value attributable to time value taken immediately to the income statement. The
pre-tax amount reclassified from equity and recognized in the income statement in production and manufacturing expenses was a loss of $4 million
(2012 $62 million loss and 2011 $195 million gain). The amount reclassified from equity and recognized in the carrying amount of non-financial assets
was a loss of $17 million (2012 $19 million loss and 2011 $13 million gain). The amounts remaining in equity at 31 December 2013 in relation to these
cash flow hedges consist of deferred gains of $85 million maturing in 2014, deferred losses of $23 million maturing in 2015 and deferred gains of $10
million maturing in 2016 and beyond.
At 31 December 2012, BP had entered into three agreements to sell its 50% interest in TNK-BP and acquire 18.5% of Rosneft, as described in Note 6.
During the period from signing until completion on 21 March 2013, these agreements represented derivative financial instruments that were required
to be measured at fair value. BP designated two of the agreements, for the acquisition of a 5.66% shareholding in Rosneft from Rosneftegaz, and for
the acquisition of a 9.80% shareholding from Rosneft, as hedging instruments in a cash flow hedge, and so changes in the fair values of these
agreements were recognized in other comprehensive income. The third agreement, under which BP sold its 50% interest in TNK-BP in exchange for
cash and a 3.04% shareholding in Rosneft, was also a derivative financial instrument, but its fair value could not be reliably measured. An asset of
$1,410 million related to these agreements was recognized on the balance sheet at 31 December 2012, of which $1,339 million related to the fair
value of the cash flow hedge derivatives. The derivatives measured at fair value at 31 December 2012 were categorized in level 3 of the fair value
hierarchy using inputs that included the quoted Rosneft share price. During 2013, a charge of $2,061 million was recognized in other comprehensive
income in relation to these agreements and $4 million was recognized in the income statement. The resulting cumulative charge of $651 million
recognized in other comprehensive income would only be recognized in the income statement if the investment in Rosneft were either sold or
impaired. The cash flow hedge derivatives were valued using the quoted Rosneft share price at the time the deal completed, of $7.60 per share.
Fair value hedges
At 31 December 2013, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk on fixed
rate debt issued by the group. The effectiveness of each hedge relationship is quantitatively assessed and demonstrated to continue to be highly
effective. The loss on the hedging derivative instruments recognized in the income statement in 2013 was $1,240 million (2012 $536 million gain and
2011 $328 million gain) offset by a gain on the fair value of the finance debt of $1,228 million (2012 $537 million loss and 2011 $327 million loss).
The interest rate and cross-currency interest rate swaps mature within one to 10 years, with an average maturity of four to five years (2012 four to five
years) and are used to convert sterling, euro, Swiss franc, Australian dollar, Canadian dollar and Hong Kong dollar denominated borrowings primarily
into US dollar floating rate debt. Note 19 outlines the group’s approach to interest rate and currency risk management.
27. Finance debt
Borrowings
Net obligations under finance leases
Disposal deposits
Current
Non-current
7,340
41
7,381
–
7,381
40,317
494
40,811
–
40,811
2013
Total
47,657
535
48,192
–
48,192
Current
Non-current
9,372
29
9,401
632
10,033
38,412
355
38,767
–
38,767
$ million
2012
Total
47,784
384
48,168
632
48,800
The main elements of current borrowings are the current portion of long-term borrowings that are due to be repaid in the next 12 months of
$6,230 million (2012 $6,240 million) and issued commercial paper of $1,050 million (2012 $3,028 million). Finance debt does not include accrued
interest, which is reported within other payables.
Deposits for disposal transactions of $632 million were included in current finance debt at 31 December 2012. This unsecured debt was extinguished
on completion of the transactions in 2013. There were no deposits for disposal transactions included within finance debt at 31 December 2013.
At 31 December 2013, $141 million (2012 $142 million) of finance debt was secured by the pledging of assets. The remainder of finance debt was
unsecured.
176
BP Annual Report and Form 20-F 2013
27. Finance debt – continued
The following table shows, by major currency, the group’s finance debt at 31 December and the weighted average interest rates achieved at those
dates through a combination of borrowings and derivative financial instruments entered into to manage interest rate and currency exposures. The
disposal deposits noted above are excluded from this analysis.
US dollar
Euro
Other currencies
US dollar
Euro
Other currencies
Fixed rate debt
Floating rate debt
Total
Weighted
average
interest
rate
%
Weighted
average
time for
which rate
is fixed
Years
3
5
4
3
5
4
4
30
7
4
2
11
Weighted
average
interest
rate
%
1
2
2
1
1
3
Amount
$ million
16,405
157
454
17,016
16,744
20
255
17,019
Amount
$ million
29,740
1,396
40
31,176
26,208
4,854
87
31,149
Amount
$ million
2013
46,145
1,553
494
48,192
2012
42,952
4,874
342
48,168
The euro debt not swapped to US dollar is naturally hedged with respect to the foreign currency risk by holding equivalent euro cash and cash
equivalent amounts.
Fair values
The estimated fair value of finance debt is shown in the table below together with the carrying amount as reflected in the balance sheet.
Long-term borrowings in the table below include the portion of debt that matures in the 12 months from 31 December 2013, whereas in the balance
sheet the amount is reported within current finance debt. The disposal deposits noted above are excluded from this analysis.
The carrying amount of the group’s short-term borrowings, comprising mainly commercial paper, approximates their fair value. The fair values of the
group’s long-term borrowings are principally determined using quoted prices in active markets (and so fall within level 1 of the fair value hierarchy) or,
where quoted prices are not available, quoted prices for similar instruments in active markets. The fair value of the group’s finance lease obligations is
estimated using discounted cash flow analyses based on the group’s current incremental borrowing rates for similar types and maturities of borrowing.
Short-term borrowings
Long-term borrowings
Net obligations under finance leases
Total finance debt
Fair
value
1,110
47,398
654
49,162
2013
Carrying
amount
1,110
46,547
535
48,192
Fair
value
3,131
45,969
520
49,620
$ million
2012
Carrying
amount
3,131
44,653
384
48,168
F
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28. Capital disclosures and analysis of changes in net debt
The group defines capital as total equity. The group’s approach to managing capital is set out in its financial framework which BP continues to refine to
support the pursuit of value growth for shareholders, whilst maintaining a secure financial base. We intend to maintain a net debt ratio within the
10-20% gearing range, and continue to hold a significant liquidity buffer while uncertainties remain.
The group monitors capital on the basis of the net debt ratio, that is, the ratio of net debt to net debt plus equity. Net debt is calculated as gross finance
debt, as shown in the balance sheet, plus the fair value of associated derivative financial instruments that are used to hedge foreign exchange and
interest rate risks relating to finance debt, for which hedge accounting is applied, less cash and cash equivalents. Net debt and net debt ratio are non-
GAAP measures. BP believes these measures provide useful information to investors. Net debt enables investors to see the economic effect of gross
debt, related hedges and cash and cash equivalents in total. The net debt ratio enables investors to see how significant net debt is relative to equity
from shareholders. The derivatives are reported on the balance sheet within the headings ‘Derivative financial instruments’. All components of equity
are included in the denominator of the calculation. At 31 December 2013, the net debt ratio was 16.2% (2012 18.7%).
During 2013, the company repurchased 753 million shares for a total amount of $5.5 billion, including fees and stamp duty, as part of its share buyback
programme announced on 22 March 2013. During 2012, the company did not repurchase any of its own shares, other than as needed to satisfy the
requirements of certain employee share-based payment plans.
At 31 December
Gross debt
Fair value (asset) liability of hedges related to finance debt
Less: cash and cash equivalents
Net debt
Equity
Net debt ratio
2013
48,192
(477)
47,715
22,520
25,195
$ million
2012
48,800
(1,700)
47,100
19,635
27,465
130,407
16.2%
119,752
18.7%
BP Annual Report and Form 20-F 2013
177
28. Capital disclosures and analysis of changes in net debt – continued
An analysis of changes in net debt is provided below.
Movement in net debt
At 1 January
Exchange adjustments
Net cash flow
Movement in finance debt relating to investing activitiesb
Other movements
At 31 December
a Including the fair value of associated derivative financial instruments.
b See Note 27 for further information.
29. Provisions
Cash and
cash
equivalents
19,635
40
2,845
–
–
22,520
2013
Net debt
(27,465)
(179)
2,009
632
(192)
(25,195)
Finance
debta
(43,075)
(75)
(3,244)
(602)
(104)
(47,100)
Cash and
cash
equivalents
14,177
64
5,394
–
–
19,635
Finance debta
(47,100)
(219)
(836)
632
(192)
(47,715)
At 1 January 2013
Exchange adjustments
New or increased provisions
Derecognition of provisions for items that cannot
be reliably estimated
Write-back of unused provisions
Transfer between categories of provision
Unwinding of discount
Change in discount rate
Utilization
Reclassified to other payables
Deletions
At 31 December 2013
Of which – current
– non-current
Of which – Gulf of Mexico oil spill
Decommissioning Environmental
Spill
response
Litigation and
claims
Clean Water
Act penalties
17,374
(37)
2,092
–
(2)
–
110
(1,602)
(500)
–
(230)
17,205
866
16,339
–
3,631
(7)
472
–
(52)
47
11
(41)
(695)
–
(1)
3,365
769
2,596
1,590
345
–
(66)
–
–
(47)
–
–
(143)
–
–
89
84
5
89
10,251
5
2,466
(379)
(38)
–
10
(20)
(3,451)
(3,933)
–
4,911
2,725
2,186
4,157
3,510
–
–
–
–
–
–
–
–
–
–
3,510
–
3,510
3,510
Other
2,872
14
464
–
(210)
–
16
(13)
(230)
–
(33)
2,880
601
2,279
–
$ million
2012
Net debt
(28,898)
(11)
2,150
(602)
(104)
(27,465)
$ million
Total
37,983
(25)
5,428
(379)
(302)
–
147
(1,676)
(5,019)
(3,933)
(264)
31,960
5,045
26,915
9,346
Further information on the financial impacts of the Gulf of Mexico oil spill is provided in Note 2.
The group makes full provision for the future cost of decommissioning oil and natural gas wells, facilities and related pipelines on a discounted basis
upon installation. The provision for the costs of decommissioning these wells, production facilities and pipelines at the end of their economic lives has
been estimated using existing technology, at current prices or future assumptions, depending on the expected timing of the activity, and discounted
using a real discount rate of 1% (2012 0.5%). The amount provided in the year for new or increased decommissioning provisions was $2,092 million
(2012 $3,766 million). The weighted average period over which these costs are generally expected to be incurred is estimated to be approximately 20
years. While the provision is based on the best estimate of future costs and the economic lives of the facilities and pipelines, there is uncertainty
regarding both the amount and timing of these costs.
Provisions for environmental remediation are made when a clean-up is probable and the amount of the obligation can be estimated reliably. Generally,
this coincides with commitment to a formal plan of action or, if earlier, on divestment or on closure of inactive sites. The provision for environmental
liabilities has been estimated using existing technology, at current prices and discounted using a real discount rate of 1% (2012 0.5%). The weighted
average period over which these costs are generally expected to be incurred is estimated to be approximately five years. The extent and cost of future
remediation programmes are inherently difficult to estimate; they depend on the scale of any possible contamination, the timing and extent of
corrective actions, and also the group’s share of the liability.
The litigation category includes provisions for matters related to, for example, commercial disputes, product liability, and allegations of exposures of
third parties to toxic substances. Included within the other category at 31 December 2013 are provisions for deferred employee compensation of $602
million (2012 $618 million). These provisions are discounted using either a nominal discount rate of 3.25% (2012 2.5%) or a real discount rate of 1%
(2012 0.5%), as appropriate.
30. Pensions and other post-retirement benefits
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 and other types of
schemes with committed pension payments). 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 such factors as the employees’
pensionable salary and length of service. Defined benefit plans may be funded or unfunded. The assets of funded plans are generally held in separately
administered trusts.
In particular, the primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their
benefit as an annuity. This pension plan is governed by a trustee board composed of four member-nominated and four company-nominated
representatives, an independent chairman, an independent director and a chief executive officer appointed by the chairman. The trustee board is
required by law to act in the best interests of the plan participants and is responsible for setting certain policies, such as investment policies of the plan.
178
BP Annual Report and Form 20-F 2013
30. Pensions and other post-retirement benefits – continued
The UK plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners in the UK are eligible for membership of a
defined contribution plan.
In the US, a range of retirement arrangements is provided. This includes a funded final salary pension plan for certain heritage employees and a cash
balance arrangement for new joiners. Retired US employees typically take their pension benefit in the form of a lump sum payment. The plan’s assets
are overseen by a fiduciary investment committee composed of seven company employees appointed by the appointing officer, who is the president
of BP Corporation North America Inc. The investment committee is required by law to act in the best interests of the plan participants and is
responsible for setting certain policies, such as the investment policies, of the plan. US employees are also eligible to participate in a defined
contribution (401k) plan in which employee contributions are matched with company contributions.
The level of contributions to funded defined benefit plans is the amount needed to provide adequate funds to meet pension obligations as they fall due.
During 2013, contributions of $597 million (2012 $884 million and 2011 $429 million) and $386 million (2012 $153 million and 2011 $777 million) were
made to the UK plans and US plans respectively. In addition, contributions of $289 million (2012 $238 million and 2011 $223 million) were made to
other funded defined benefit plans. The aggregate level of contributions in 2014 is expected to be approximately $1,250 million, and includes
contributions in all countries that we expect to be required to make by law or under contractual agreements as well as an allowance for discretionary
funding.
For the primary UK plan there is an agreement between the group and the trustee under which contributions are determined annually based on the
funding level of the plan. Under this agreement a proportion of any deficit and the service cost is funded in the following year. Contributions in the US
are determined by legislation and are supplemented by discretionary contributions.
Certain group companies, principally in the US, provide post-retirement healthcare and life insurance benefits to retired employees and their
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 obligation and cost of providing pensions and other post-retirement benefits is assessed annually using the projected unit credit method. The date
of the most recent actuarial review was 31 December 2013. The group’s principal plans are subject to a formal actuarial valuation every three years in
the UK, with valuations being required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension plans
was as at 31 December 2011.
The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are reviewed by
management at the end of each year, and are used to evaluate accrued pension and other post-retirement benefits at 31 December and pension
expense for the following year.
Financial assumptions used to determine benefit obligation
Discount rate for pension plan liabilities
Discount rate for other post-retirement benefit plan
liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inflation for pension plan liabilities
Financial assumptions used to determine benefit expense
Discount rate for pension plan service cost
Discount rate for pension plan other finance expense
Discount rate for other post-retirement benefit plan
service cost
Inflation for pension plan service cost
2013
4.6
n/a
5.1
3.3
3.3
3.3
2013
4.4
4.4
n/a
3.1
2012
4.4
n/a
4.9
3.1
3.1
3.1
2012
4.8
4.8
n/a
3.2
UK
2011
4.8
n/a
5.1
3.2
3.2
3.2
UK
2011
5.5
5.5
n/a
3.5
2013
4.3
4.5
3.9
–
–
2.1
2013
3.2
3.2
3.7
2.4
2012
3.2
3.7
4.2
–
–
2.4
2012
4.3
4.3
4.5
1.9
US
2011
4.3
4.5
3.7
–
–
1.9
US
2011
4.7
4.7
5.3
2.3
2013
3.9
n/a
3.7
1.7
1.3
2.2
2013
3.6
3.6
n/a
2.2
2012
3.6
n/a
3.7
1.7
1.2
2.2
2012
4.7
4.7
n/a
2.2
%
Other
2011
4.7
n/a
3.7
1.7
1.2
2.2
Other
2011
5.3
5.3
n/a
2.3
Our discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and Germany we use yields
that reflect the maturity profile of the expected benefit payments. The inflation rate assumptions for our UK and US plans are based on the difference
between the yields on index-linked and fixed-interest long-term government bonds. In other countries we use either this approach, or the central bank
inflation target, or advice from the local actuary depending on the information that is available to us. The inflation assumptions are used to determine
the rate of increase for pensions in payment and the rate of increase in deferred pensions where there is such an increase.
Our assumptions for the rate of increase in salaries are based on our inflation assumption plus an allowance for expected long-term real salary growth.
These include allowance for promotion-related salary growth, of between 0.3% and 1.0% depending on country.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best
practice in the countries in which we provide pensions, and have been chosen with regard to the latest available published tables adjusted where
appropriate to reflect the experience of the group and an extrapolation of past longevity improvements into the future. BP’s most substantial pension
liabilities are in the UK, the US and Germany where our mortality assumptions are as follows:
Mortality assumptions
Life expectancy at age 60 for a male currently aged 60
Life expectancy at age 60 for a male currently aged 40
Life expectancy at age 60 for a female currently aged 60
Life expectancy at age 60 for a female currently aged 40
a Minor amendments have been made to comparative amounts.
2013
27.8
30.7
29.5
32.2
2012
27.7
30.6
29.4
32.1
UK
2011
27.6
30.5
29.3
32.0
2013
24.9
26.4
26.5
27.3
2012
24.9
26.3
26.4
27.3
US
2011
24.8
26.3
26.4
27.3
2013
23.3
26.1
27.8
30.5
2012
23.1
26.0
27.7
30.3
Years
Germanya
2011
23.0
25.8
27.5
30.2
BP Annual Report and Form 20-F 2013
179
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
30. Pensions and other post-retirement benefits – continued
Our assumption for future US healthcare cost trend rate for the first year after the reporting date reflects the rate of actual cost increases seen in
recent years. The ultimate trend rate reflects our long-term expectations of the level at which cost inflation will stabilize based on past healthcare cost
inflation seen over a longer period of time. The assumed future US healthcare cost trend rate assumptions are as follows:
First year’s US healthcare cost trend rate
Ultimate US healthcare cost trend rate
Year in which ultimate trend rate is reached
2013
7.3
5.0
2021
2012
7.3
5.0
2020
%
2011
7.6
5.0
2020
Pension plan assets are generally held in trusts. The primary objective of the trusts is to accumulate pools of assets sufficient to meet the obligations
of the various plans. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices
in portfolio management.
A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term with an acceptable level of risk.
In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the total portfolio, the investment
portfolios are highly diversified.
The current long-term asset allocation policy for the major plans is as follows:
Asset category
Total equity
Bonds/cash
Property/real estate
UK
70
23
7
US
60
40
–
%
Other
17-65
25-78
0-10
The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary. Some of the
group’s pension plans use derivative financial instruments as part of their asset mix to manage the level of risk.
For the primary UK pension plan there is an agreement with the trustee to reduce the proportion of plan assets held as equities and increase the
proportion held as bonds at certain market trigger points, over time, with a view to better matching the pension liabilities. During 2013 the first trigger
point was reached. There is a similar agreement in place in the US where trigger points were reached in 2011 and 2013.
BP’s main plans in the UK and US do not currently follow a liability driven investment (‘LDI’) approach, a form of investing designed to match the
movement in pension plan assets with the movement in projected benefit obligations over time.
180
BP Annual Report and Form 20-F 2013
30. Pensions and other post-retirement benefits – continued
The fair values of the various categories of assets held by the defined benefit plans at 31 December are presented in the table below, including the
effects of derivative financial instruments. Movements in the fair value of plan assets during the year are shown in detail in the table on page 182.
Fair value of pension plan assets
At 31 December 2013
Listed equities – developed markets
– emerging markets
Private equity
Government issued nominal bonds
Index-linked bonds
Corporate bonds
Property
Cash
Other
At 31 December 2012
Listed equities – developed markets
– emerging markets
Private equity
Government issued nominal bonds
Index-linked bonds
Corporate bonds
Property
Cash
Other
At 31 December 2011
Listed equities – developed markets
– emerging markets
Private equity
Government issued nominal bonds
Index-linked bonds
Corporate bonds
Property
Cash
Other
UK
pension
plansa
US
pension
plansb
US other
post-
retirement
benefit
plans
$ million
Other
plans
Total
17,341
2,290
2,907
549
787
4,427
2,200
855
160
31,516
15,659
1,074
2,879
544
491
3,850
1,783
1,000
66
27,346
13,622
890
2,690
513
390
3,238
1,710
470
64
23,587
3,260
308
1,432
1,259
–
1,323
6
135
55
7,778
3,622
341
1,468
904
–
1,255
5
86
105
7,786
3,328
299
1,407
733
–
1,289
4
88
56
7,204
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
1
–
–
–
–
–
–
–
4
–
4
913
84
6
1,258
69
982
134
278
113
3,837
844
89
7
1,042
78
766
139
321
247
3,533
754
69
8
993
123
724
117
326
172
3,286
21,514
2,682
4,345
3,066
856
6,732
2,340
1,268
328
43,131
20,125
1,504
4,354
2,490
569
5,871
1,927
1,408
418
38,666
17,704
1,258
4,105
2,239
513
5,251
1,831
888
292
34,081
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
a Bonds held by the UK pension fund are typically denominated in sterling. Property held by the UK pension fund is in the United Kingdom.
b Bonds held by the US pension fund are typically denominated in US dollars.
BP Annual Report and Form 20-F 2013
181
30. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service costb
Settlement
Operating charge relating to defined benefit plans
Payments to defined contribution plans
Total operating charge
Interest income on plan assets
Interest on plan liabilities
Other finance expense
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assetsa
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Remeasurements recognized in other comprehensive income
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Operating charge relating to defined benefit plans
Interest cost
Contributions by plan participantsc
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Disposals
Remeasurements
Benefit obligation at 31 Decembera e
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsa
Contributions by plan participantsc
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Disposals
Remeasurementsf
Fair value of plan assets at 31 December
Surplus (deficit) at 31 December
Represented by
Asset recognized
Liability recognized
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded
plans as follows
Funded
Unfunded
UK
pension
plans
US
pension
plans
US other
post-
retirement
benefit
plans
$ million
2013
Total
1,081
(44)
(1)
1,036
300
1,336
(1,509)
1,989
480
3,515
1,503
(51)
(203)
4,764
52,281
837
1,036
1,989
50
(2,644)
(684)
(83)
(1,249)
51,533
38,666
785
1,509
50
1,272
(2,644)
(22)
3,515
43,131
Other
plans
177
27
(1)
203
53
256
(130)
362
232
114
283
(65)
5
337
10,148
132
203
362
13
(192)
(395)
(13)
(223)
10,035
3,533
(37)
130
13
289
(192)
(13)
114
3,837
358
(49)
–
309
223
532
(240)
305
65
730
1,054
14
(205)
1,593
10,029
–
309
305
–
(1,364)
(52)
–
(863)
8,364
7,786
–
240
–
386
(1,364)
–
730
7,778
49
–
–
49
–
49
–
101
101
–
106
–
(44)
62
2,845
–
49
101
–
(1)
(233)
(61)
(62)
2,638
1
–
–
–
–
(1)
–
–
–
(586)
(2,638)
(6,198)
(8,402)
6
(592)
(586)
(5)
(581)
(586)
–
(2,638)
(2,638)
–
(2,638)
(2,638)
79
(6,277)
(6,198)
(320)
(5,878)
(6,198)
1,376
(9,778)
(8,402)
960
(9,362)
(8,402)
(30,231)
(265)
(30,496)
(7,783)
(581)
(8,364)
–
(2,638)
(2,638)
(4,157)
(5,878)
(10,035)
(42,171)
(9,362)
(51,533)
497
(22)
–
475
24
499
(1,139)
1,221
82
2,671
60
–
41
2,772
29,259
705
475
1,221
37
(1,087)
(4)
(9)
(101)
30,496
27,346
822
1,139
37
597
(1,087)
(9)
2,671
31,516
1,020
1,291
(271)
1,020
1,285
(265)
1,020
a The costs of managing the plan’s investments are treated as being part of the return on plan assets, the costs of administering our pension plan benefits are generally included in current service cost
and the costs of administering our other post-retirement benefit plans are included in the benefit obligation.
b Past service costs include a credit of $73 million as the result of a curtailment in the pension arrangements of a number of employees in the UK and US following divestment transactions. A charge of
$29 million for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $3,269 million benefits plus $59 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for other plans includes $4,874 million for the German plan, which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurment of plan assets as disclosed above.
182
BP Annual Report and Form 20-F 2013
30. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service costb
Settlement
Operating charge relating to defined benefit plans
Payments to defined contribution plans
Total operating charge
Interest income on plan assets
Interest on plan liabilities
Other finance expense
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assetsa
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Remeasurements recognized in other comprehensive income
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustments
Operating charge relating to defined benefit plans
Interest cost
Contributions by plan participantsc
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Disposals
Remeasurements
Benefit obligation at 31 Decembera e
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsa
Contributions by plan participantsc
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Disposals
Remeasurementsf
Fair value of plan assets at 31 December
Deficit at 31 December
Represented by
Asset recognized
Liability recognized
The surplus (deficit) may be analysed between funded and unfunded plans as follows
Funded
Unfunded
The defined benefit obligation may be analysed between funded and unfunded
plans as follows
Funded
Unfunded
UK
pension
plans
US pension
plans
US other
post-
retirement
benefit
plans
477
(1)
–
476
14
490
(1,146)
1,249
103
1,523
(1,446)
–
(116)
(39)
25,675
1,313
476
1,249
39
(1,038)
(7)
(10)
1,562
29,259
23,587
1,215
1,146
39
884
(1,038)
(10)
1,523
27,346
328
20
–
348
223
571
(304)
382
78
718
(1,427)
–
68
(641)
8,617
–
348
382
–
(593)
(84)
–
1,359
10,029
7,204
–
304
–
153
(593)
–
718
7,786
51
–
–
51
–
51
–
134
134
–
187
52
(48)
191
3,061
–
51
134
–
(3)
(207)
–
(191)
2,845
4
–
–
–
–
(3)
–
–
1
Other
plans
151
82
1
234
44
278
(154)
405
251
173
(1,093)
(37)
(126)
(1,083)
8,801
254
234
405
14
(230)
(394)
(192)
1,256
10,148
3,286
88
154
14
238
(230)
(190)
173
3,533
$ million
2012
Total
1,007
101
1
1,109
281
1,390
(1,604)
2,170
566
2,414
(3,779)
15
(222)
(1,572)
46,154
1,567
1,109
2,170
53
(1,864)
(692)
(202)
3,986
52,281
34,081
1,303
1,604
53
1,275
(1,864)
(200)
2,414
38,666
(1,913)
(2,243)
(2,844)
(6,615)
(13,615)
–
(1,913)
(1,913)
(1,688)
(225)
(1,913)
–
(2,243)
(2,243)
(1,599)
(644)
(2,243)
–
(2,844)
(2,844)
(43)
(2,801)
(2,844)
12
(6,627)
(6,615)
(539)
(6,076)
(6,615)
12
(13,627)
(13,615)
(3,869)
(9,746)
(13,615)
(29,034)
(225)
(29,259)
(9,385)
(644)
(10,029)
(44)
(2,801)
(2,845)
(4,072)
(6,076)
(10,148)
(42,535)
(9,746)
(52,281)
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
a The costs of managing the plan’s investments are treated as being part of the return on plan assets, the costs of administering our pension plan benefits are generally included in current service cost
and the costs of administering our other post-retirement benefit plans are included in the benefit obligation.
b Past service costs are charges for special termination benefits representing the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $2,501 million benefits plus $55 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for other plans includes $4,783 million for the German plan, which is largely unfunded.
f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
BP Annual Report and Form 20-F 2013
183
30. Pensions and other post-retirement benefits – continued
Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service cost
Settlement
Operating charge relating to defined benefit plans
Payments to defined contribution plans
Total operating charge
Analysis of the amount credited (charged) to other finance expense
Interest income on plan assets
Interest on plan liabilities
Other finance (income) expense
Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assetsa
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of the plan
liabilities
Experience gains and losses arising on the plan liabilities
Remeasurements recognized in other comprehensive income
UK
pension
plans
US pension
plans
US other
post-
retirement
benefit
plans
383
3
–
386
5
391
(1,361)
1,263
(98)
(1,552)
(2,251)
(429)
(84)
(4,316)
280
184
–
464
199
663
(304)
369
65
224
(468)
(44)
(102)
(390)
53
–
–
53
–
53
–
163
163
(1)
(63)
102
89
127
$ million
2011
Total
851
230
4
1,085
245
1,330
(1,843)
2,243
400
(1,383)
(3,418)
(377)
(123)
(5,301)
Other
plans
135
43
4
182
41
223
(178)
448
270
(54)
(636)
(6)
(26)
(722)
a The costs of managing the plan’s investments are treated as being part of the return on plan assets, the costs of administering our pension plan benefits are generally included in current service cost
and the costs of administering our other post-retirement benefit plans are included in the benefit obligation.
At 31 December 2013, reimbursement balances due from or to other companies in respect of pensions amounted to $399 million reimbursement
assets (2012 $381 million) and $15 million reimbursement liabilities (2012 $15 million). These balances are not included as part of the pension
surpluses and deficits, but are reflected within other receivables and other payables in the group balance sheet.
Sensitivity analysis
The discount rate, inflation, salary growth, US healthcare cost trend rate and the mortality assumptions all have a significant effect on the amounts
reported. A one-percentage point change, in isolation, in certain assumptions as at 31 December 2013 for the group’s plans would have had the effects
shown in the table below. The effects shown for the expense in 2014 comprise the total of current service cost and net finance income or expense.
Discount ratea
Effect on pension and other post-retirement benefit expense in 2014
Effect on pension and other post-retirement benefit obligation at 31 December 2013
Inflation rate
Effect on pension and other post-retirement benefit expense in 2014
Effect on pension and other post-retirement benefit obligation at 31 December 2013
Salary growth
Effect on pension and other post-retirement benefit expense in 2014
Effect on pension and other post-retirement benefit obligation at 31 December 2013
US healthcare cost trend rate
Effect on US other post-retirement benefit expense in 2014
Effect on US other post-retirement obligation at 31 December 2013
$ million
One percentage point
Decrease
Increase
(474)
(6,918)
521
7,120
142
1,300
16
278
481
9,059
(397)
(5,658)
(123)
(1,158)
(13)
(233)
a The amounts presented reflect that the discount rate is used to determine the asset interest income as well as the interest cost on the obligation.
One additional year of longevity in the mortality assumptions would have the effects shown in the table below. The effect shown for the expense in
2014 comprises the total of current service cost and net finance income or expense.
One additional year’s longevity
Effect on pension and other post-retirement benefit expense in 2014
Effect on pension and other post-retirement benefit obligation at 31 December 2013
184
BP Annual Report and Form 20-F 2013
UK
pension
plans
52
927
US
pension
plans
5
95
US other
post-
retirement
benefit
plans
3
46
$ million
German
pension
plans
9
213
30. Pensions and other post-retirement benefits – continued
Estimated future benefit payments and the weighted average duration of defined benefit obligations
The expected benefit payments, which reflect expected future service, as appropriate, but exclude plan expenses, up until 2023 and the weighted
average duration of the defined benefit obligations at the end of the reporting period are as follows:
Estimated future benefit payments
2014
2015
2016
2017
2018
2019-2023
US
other post-
retirement
benefit
plans
174
177
178
178
178
874
US
pension
plans
690
715
726
733
735
3,533
UK
pension
plans
1,153
1,201
1,265
1,281
1,361
7,282
Other plans
596
585
582
570
560
2,651
Weighted average duration
17.6
8.3
10.5
13.2
31. Called-up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
Issued
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share-based payment plansb
Repurchase of ordinary share capitalc
At 31 December
Shares
thousand
7,233
5,473
20,959,159
202,124
18,203
(752,854)
20,426,632
2013
$ million
12
9
21
Shares
thousand
7,233
5,473
5,240 20,813,410
138,406
7,343
–
51
5
(188)
5,108 20,959,159
5,129
2012
$ million
12
9
21
5,203
35
2
–
5,240
5,261
Shares
thousand
7,233
5,473
20,647,160
165,601
649
–
20,813,410
$ million
Total
2,613
2,678
2,751
2,762
2,834
14,340
years
2011
$ million
12
9
21
5,162
41
–
–
5,203
5,224
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference
shares.
b The nominal value of new shares issued for the employee share plans in 2011 amounted to $162,000. Consideration received relating to the issue of new shares for employee share plans amounted to
$116 million (2012 $47 million and 2011 $4 million).
c Purchased for a total consideration of $5,493 million, including transaction costs of $30 million. All shares purchased were for cancellation. The repurchased shares represented 3.6% of ordinary share
capital.
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 £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.
During 2013 the company repurchased 753 million ordinary shares at a cost of $5,463 million as part of the share repurchase programme announced
on 22 March 2013. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the year-end commitment
to repurchase shares subsequent to the end of the year, for which an amount of $1,430 million has been accrued at 31 December 2013 (2012 nil).
Treasury shares
At 1 January
Shares re-issued for employee share-based payment plans
At 31 December
2013
2012
2011
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
Shares
thousand
Nominal value
$ million
1,823,408
(35,469)
1,787,939
455
(8)
1,837,508
(14,100)
459
(4)
1,850,699
(13,191)
447
1,823,408
455
1,837,508
462
(3)
459
For each year presented, the balance at 1 January represents the maximum number of shares held in treasury during the year, representing 8.7%
(2012 8.8% and 2011 9.0%) of the called-up ordinary share capital of the company.
During 2013, the movement in treasury shares represented less than 0.2% (2012 less than 0.1% and 2011 less than 0.1%) of the ordinary share
capital of the company.
BP Annual Report and Form 20-F 2013
185
32. Capital and reserves
At 1 January 2013
Profit for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Share of items relating to equity-accounted entities, net of tax
Total comprehensive income
Dividends
Repurchases of ordinary share capital
Share-based payments, net of taxa
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2013
At 1 January 2012
Profit for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Share of items relating to equity-accounted entities, net of tax
Total comprehensive income
Dividends
Share-based payments, net of taxa
Transactions involving non-controlling interests
At 31 December 2012
At 1 January 2011
Profit for the year
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Total comprehensive income
Dividends
Share-based payments, net of taxa
Transactions involving non-controlling interests
At 31 December 2011
Share
capital
5,261
Share
premium
account
9,974
Capital
redemption
reserve
Merger
reserve
Total
share capital
and capital
reserves
1,072
27,206
43,513
–
–
–
–
–
–
–
–
–
51
(188)
5
–
–
–
–
–
–
–
–
–
–
–
(51)
–
138
–
–
–
–
–
–
–
–
–
–
–
–
188
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
143
–
–
5,129
10,061
1,260
27,206
43,656
Share
capital
5,224
Share
premium
account
9,952
Capital
redemption
reserve
Merger
reserve
Total
share capital
and capital
reserves
1,072
27,206
43,454
–
–
–
–
–
–
–
–
–
35
2
–
–
–
–
–
–
–
–
–
–
(35)
57
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
59
–
5,261
9,974
1,072
27,206
43,513
Share
capital
5,183
Share
premium
account
9,987
Capital
redemption
reserve
Merger
reserve
Total
share capital
and capital
reserves
1,072
27,206
43,448
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
41
–
–
5,224
–
(41)
6
–
9,952
–
–
–
–
1,072
–
–
–
–
27,206
–
–
6
–
43,454
a Includes new share issues and movements in own shares and treasury shares where these relate to employee share-based payment plans.
186
BP Annual Report and Form 20-F 2013
Own
shares
Treasury
shares
Total
own shares
and treasury
shares
Foreign
currency
translation
reserve
Available-
for-sale
investments
(280)
(20,774)
(21,054)
5,128
–
–
–
–
–
–
–
–
–
–
–
(321)
–
–
(601)
–
–
–
–
–
–
–
–
–
–
–
404
–
–
–
–
–
–
–
–
–
–
–
–
–
83
–
–
(20,370)
(20,971)
Own
shares
Treasury
shares
Total own
shares and
treasury
shares
(388)
(20,935)
(21,323)
–
–
–
–
–
–
–
–
–
–
108
–
–
–
–
–
–
–
–
–
–
–
161
–
–
–
–
–
–
–
–
–
–
–
269
–
–
(1,603)
–
–
–
–
–
–
(1,603)
–
–
–
–
–
3,525
Foreign
currency
translation
reserve
4,509
–
619
–
–
–
–
–
–
619
–
–
–
(280)
(20,774)
(21,054)
5,128
Available-
for-sale
investments
Cash flow
hedges
389
–
–
296
–
–
–
–
–
296
–
–
–
685
(122)
–
(5)
–
1,217
–
–
–
–
1,212
–
–
–
1,090
Own
shares
Treasury
shares
Total own
shares and
treasury
shares
(126)
(21,085)
(21,211)
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(262)
–
(388)
–
–
150
–
(20,935)
–
–
(112)
–
(21,323)
Foreign
currency
translation
reserve
5,036
–
(527)
–
–
–
–
(527)
–
–
–
4,509
Available-
for-sale
investments
Cash flow
hedges
463
–
–
(74)
–
–
–
(74)
–
–
–
389
6
–
(1)
–
(127)
–
–
(128)
–
–
–
(122)
Cash flow
hedges
1,090
–
Total
fair value
reserves
1,775
–
–
–
(1,785)
–
–
–
–
(1,785)
–
–
–
–
–
(695)
–
(685)
(1,785)
–
–
–
–
(2,470)
–
–
–
–
–
685
–
–
(685)
–
–
–
–
–
(685)
–
–
–
–
–
–
Share-
based
payment
reserve
1,608
–
–
–
–
–
–
–
–
–
–
–
97
–
–
Profit and
loss
account
87,576
23,451
–
–
–
(24)
(25)
3,243
2
26,647
(5,441)
(6,923)
150
73
–
BP
shareholders’
equity
Non-
controlling
interests
$ million
Total
equity
118,546
23,451
1,206
119,752
307
23,758
(1,603)
(685)
(1,785)
(24)
(25)
3,243
2
22,574
(5,441)
(6,923)
473
73
–
(15)
–
–
–
–
–
–
292
(469)
–
–
–
76
(1,618)
(685)
(1,785)
(24)
(25)
3,243
2
22,866
(5,910)
(6,923)
473
73
76
(695)
1,705
102,082
129,302
1,105
130,407
Total fair
value
reserves
267
–
(5)
296
1,217
–
–
–
–
1,508
–
–
–
1,775
Total fair
value
reserves
469
–
(1)
(74)
(127)
–
–
(202)
–
–
–
267
Share-
based
payment
reserve
1,582
–
–
–
–
–
–
–
–
–
–
26
–
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Profit and
loss
account
83,079
11,017
BP
shareholders’
equity
111,568
11,017
Non-
controlling
interests
Total
equity
1,017
112,585
234
11,251
–
–
–
(39)
23
(1,134)
(6)
9,861
(5,294)
(70)
–
614
296
1,217
(39)
23
(1,134)
(6)
11,988
(5,294)
284
–
2
–
–
–
–
2
–
238
(82)
–
33
616
296
1,217
(39)
23
(1,132)
(6)
12,226
(5,376)
284
33
1,608
87,576
118,546
1,206
119,752
Share-
based
payment
reserve
1,586
–
–
–
–
–
–
–
–
(4)
–
1,582
Profit and
loss
account
65,754
25,212
BP
shareholders’
equity
95,082
25,212
–
–
–
(39)
(3,831)
21,342
(4,072)
102
(47)
83,079
(528)
(74)
(127)
(39)
(3,831)
20,613
(4,072)
(8)
(47)
111,568
Non-
controlling
interests
904
397
(10)
–
–
–
Total
equity
95,986
25,609
(538)
(74)
(127)
(39)
(3)
(3,834)
384
(245)
–
(26)
1,017
20,997
(4,317)
(8)
(73)
112,585
BP Annual Report and Form 20-F 2013
187
32. Capital and reserves – continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including treasury
shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in
an acquisition made by the issue of shares.
Own shares
Own shares represent BP shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based
payment plans. The ESOPs have waived their rights to dividends on shares held for future awards and are funded by the group. Until such time as the
company’s own shares held by the ESOPs vest unconditionally to employees, the amount paid for those shares is shown as a reduction in
shareholders’ equity. Assets and liabilities of the ESOPs are recognized as assets and liabilities of the group.
At 31 December 2013, the ESOPs held 32,748,354 shares (2012 22,428,179 shares and 2011 27,784,503 shares) for potential future awards, which
had a market value of $253 million (2012 $154 million and 2011 $197 million). At 31 December 2013, a further 12,856,914 ordinary share equivalents
(2012 18,673,926 ordinary share equivalents) were held by the group in the form of ADSs to meet the requirements of employee share-based payment
plans in the US.
Treasury shares
Treasury shares represent BP shares repurchased and available for re-issue.
Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial statements of foreign operations.
Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement.
Available-for-sale investments
This reserve records the changes in fair value of available-for-sale investments except for impairment losses, foreign exchange gains or losses, or
changes arising from revised estimates of future cash flows. On disposal or impairment of the investments, the cumulative changes in fair value are
recycled to the income statement.
Cash flow hedges
This reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. For
further information see Note 1.
Share-based payment reserve
This reserve represents cumulative amounts charged to profit in respect of employee share-based payment plans where the scheme has not yet been
settled by means of an award of shares to an individual.
Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.
188
BP Annual Report and Form 20-F 2013
32. Capital and reserves – continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Share of items relating to equity-accounted entities, net of tax
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Share of items relating to equity-accounted entities, net of tax
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Other comprehensive income
33. Employee costs and numbers
Employee costs
Wages and salariesa b
Social security costs
Share-based paymentsc
Pension and other post-retirement benefit costs
Number of employees at 31 Decemberd
Upstream
Downstreame
Other businesses and corporatef
Gulf Coast Restoration Organization
By geographical area
US
Non-USe
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
$ million
2013
Pre-tax
Tax
Net of tax
(1,586)
(695)
(1,979)
(24)
–
4,764
2
482
(32)
10
194
–
(25)
(1,521)
–
(1,374)
(1,618)
(685)
(1,785)
(24)
(25)
3,243
2
(892)
$ million
2012
Pre-tax
Tax
Net of tax
470
305
1,547
(39)
–
(1,572)
(6)
705
146
(9)
(330)
–
23
440
–
270
616
296
1,217
(39)
23
(1,132)
(6)
975
$ million
2011
Pre-tax
Tax
Net of tax
(524)
(74)
(164)
(39)
(14)
–
37
–
(538)
(74)
(127)
(39)
(5,301)
(6,102)
1,467
1,490
(3,834)
(4,612)
2013
10,161
958
719
1,816
13,654
2013
24,700
48,000
11,100
100
83,900
19,600
64,300
83,900
2012
9,910
908
674
1,956
$ million
2011
9,333
854
584
1,730
13,448
12,501
2012
24,200
51,800
10,300
100
86,400
23,400
63,000
86,400
2011
22,400
51,500
10,100
100
84,100
22,900
61,200
84,100
BP Annual Report and Form 20-F 2013
189
33. Employee costs and numbers – continued
Average number of employeesd
US
Non-US
Upstream
Downstream
Other businesses and corporate
Gulf Coast Restoration Organization
9,400
9,300
1,900
100
20,700
15,100
39,800
9,000
–
63,900
2013
Total
24,500
49,100
10,900
100
84,600
US
Non-US
9,300
12,000
1,900
100
23,300
14,100
39,900
8,700
–
62,700
2012
Total
23,400
51,900
10,600
100
86,000
US
Non-US
8,500
12,300
1,700
100
22,600
13,400
39,700
6,500
–
59,600
2011
Total
21,900
52,000
8,200
100
82,200
a Includes termination payments of $212 million (2012 $77 million and 2011 $126 million).
b Wages and salaries for 2012 and 2011 have been amended.
c The group provides certain employees with shares and share options as part of their remuneration packages. The majority of these share-based payment arrangements are equity-settled.
d Reported to the nearest 100.
e Includes 14,100 (2012 14,700 and 2011 14,600) service station staff.
f Includes 4,300 (2012 3,600 and 2011 4,000) agricultural, operational and seasonal workers in Brazil.
34. Remuneration of directors and senior management
Remuneration of directors
Total for all directors
Emoluments
Gains made on exercise of share options
Amounts awarded under incentive schemes
Total
2013
2012
16
–
2
18
12
–
3
15
$ million
2011
10
–
1
11
Emoluments
These amounts comprise fees and benefits paid to the non-executive chairman and the non-executive directors and, for executive directors, salary and
benefits earned during the relevant financial year, plus cash bonuses awarded for the year. There was no compensation for loss of office in 2013 (2012
nil and 2011 nil).
Pension contributions
During 2013 two executive directors participated in a non-contributory pension scheme established for UK employees. Two US executive directors
participated in the US BP Retirement Accumulation Plan during 2013.
Office facilities for former chairmen and deputy chairmen
It is customary for the company to make available to former chairmen and deputy chairmen, who were previously employed executives, the use of
office and basic secretarial facilities following their retirement. The cost involved in doing so is not significant.
Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 81.
Remuneration of directors and senior management
Total for all senior management
Total for all senior management
Short-term employee benefits
Pensions and other post-retirement benefits
Share-based payments
Total
2013
2012a
36
3
43
82
29
3
37
69
$ million
2011a
34
3
28
65
a Prior year comparatives have been amended to include the portion of bonuses that were deferred and will be settled in shares in the future.
Senior management, in addition to executive and non-executive directors, includes other senior managers who are members of the executive
management team.
Short-term employee benefits
In addition to fees and benefits paid to the non-executive chairman and non-executive directors, these amounts comprise, for executive directors and
senior managers, salary and benefits earned during the year, plus cash bonuses awarded for the year. Deferred annual bonus awards, to be settled in
shares, are included in share-based payments. Short-term employee benefits includes compensation for loss of office of $3 million (2012 nil and 2011
$9 million).
Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing defined benefit pensions and other post-retirement benefits to senior
management in respect of the current year of service measured in accordance with IAS 19 ‘Employee Benefits’.
Share-based payments
This is the cost to the group of senior management’s participation in share-based payment plans, as measured by the fair value of options and shares
granted accounted for in accordance with IFRS 2 ‘Share-based Payments’. The main plans in which senior management have participated are the
EDIP, DAB, ACBD, SVP and RSP.
190
BP Annual Report and Form 20-F 2013
35. Contingent liabilities
Contingent liabilities related to the Gulf of Mexico oil spill
Details of contingent liabilities related to the Gulf of Mexico oil spill are set out in Note 2.
Contingent liabilities not related to the Gulf of Mexico oil spill
There were contingent liabilities at 31 December 2013 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. Further information is included in Note 19.
Lawsuits arising out of the Exxon Valdez oil spill in Prince William Sound, Alaska, in March 1989 were filed against Exxon (now ExxonMobil), Alyeska
Pipeline Service Company (Alyeska), which operates the oil terminal at Valdez, and the other oil companies that own Alyeska. Alyeska initially
responded to the spill until the response was taken over by Exxon. BP owns a 46.9% interest (reduced during 2001 from 50% by a sale of 3.1% to
Phillips) in Alyeska through a subsidiary of BP America Inc. and briefly indirectly owned a further 20% interest in Alyeska following BP‘s combination
with Atlantic Richfield Company (Atlantic Richfield). 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 that Exxon has incurred. BP will defend any
such claims vigorously. It is not possible to estimate any financial effect.
In the normal course of the group‘s business, legal proceedings are pending or may be brought against BP group entities arising out of current and past
operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims, consumer protection,
general environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in paint, asbestos and other chemicals.
BP believes that the impact of these legal proceedings on the group‘s results of operations, liquidity or financial position will not be material.
With respect to lead pigment in paint in particular, Atlantic Richfield, a subsidiary of BP, has been named as a co-defendant in numerous lawsuits
brought in the US alleging injury to persons and property. Although it is not possible to predict the outcome of the legal proceedings, Atlantic Richfield
believes it has valid defences that render the incurrence of a liability remote; however, the amounts claimed and the costs of implementing the
remedies sought in the various cases could be substantial. The majority of the lawsuits have been abandoned or dismissed against Atlantic Richfield.
No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse judgment in any proceeding. Atlantic
Richfield intends to defend such actions vigorously.
The group files tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group‘s tax returns. Tax
returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the resolution of tax positions
through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is difficult to predict the ultimate
outcome in some cases, the group does not anticipate that there will be any material impact upon the group‘s results of operations, financial position or
liquidity.
The group is subject to numerous national and local environmental laws and regulations concerning its products, operations and other activities. These
laws and regulations may require the group to take future action to remediate the effects on the environment of prior disposal or release of chemicals
or petroleum substances by the group or other parties. Such contingencies may exist for various sites including refineries, chemical plants, oil fields,
service stations, terminals and waste disposal sites. In addition, the group may have obligations relating to prior asset sales or closed facilities. The
ultimate requirement for remediation and its cost are inherently difficult to estimate. However, the estimated cost of known environmental obligations
has been provided in these accounts in accordance with the group‘s accounting policies. While the amounts of future costs that are not provided for
could be significant and could be material to the group‘s results of operations in the period in which they are recognized, it is not possible to estimate
the amounts involved. BP does not expect these costs to have a material effect on the group‘s financial position or liquidity.
The group also has obligations to decommission oil and natural gas production facilities and related pipelines. Provision is made for the estimated costs
of these activities, however there is uncertainty regarding both the amount and timing of these costs, given the long-term nature of these obligations.
BP believes that the impact of any reasonably foreseeable changes to these provisions on the group‘s results of operations, financial position or
liquidity will not be material. If oil and natural gas production facilities and pipelines are sold to third parties and the subsequent owner is unable to
meet their decommissioning obligations, judgement must be used to determine whether BP is then responsible for decommissioning, and if so the
extent of that responsibility.
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 premiums with attendant transaction costs. The position is reviewed periodically.
36. Capital commitments
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at 31 December
2013 amounted to $13,705 million (2012 $14,894 million). BP’s share of capital commitments of joint ventures amounted to $317 million (2012 $293
million).
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2013
191
37. Auditor’s remuneration
Fees – EY
The audit of the company annual accountsa
The audit of accounts of any subsidiaries of the company
Total audit
Audit-related assurance servicesb
Total audit and audit-related assurance services
Taxation compliance services
Taxation advisory services
Services relating to corporate finance transactions
Other assurance services
Total non-audit or non-audit-related assurance services
Services relating to BP pension plansc
2013
2012
$ million
2011
26
13
39
8
47
1
1
2
1
5
1
26
13
39
7
46
2
2
2
1
7
1
26
15
41
6
47
1
1
4
1
7
1
53
54
55
a Fees in respect of the audit of the accounts of BP p.l.c. including the group’s consolidated financial statements.
b Includes interim reviews and reporting on internal financial controls and non-statutory audit services.
c The pension plan services include tax compliance services of $240,000 (2012 $50,000 and 2011 $108,000).
2013 includes $3 million of additional fees for 2012, and 2012 includes $2 million of additional fees for 2011. Auditors’ remuneration is included in the
income statement within distribution and administration expenses.
The tax services relate to income tax and indirect tax compliance, employee tax services and tax advisory services.
The audit committee has established pre-approval policies and procedures for the engagement of Ernst & Young to render audit and certain assurance
and tax services. The audit fees payable to Ernst & Young are reviewed by the audit committee in the context of other global companies for cost-
effectiveness. Ernst & Young performed further assurance and tax services that were not prohibited by regulatory or other professional requirements
and were pre-approved by the committee. Ernst & Young is engaged for these services when its expertise and experience of BP are important. Most
of this work is of an audit nature. Tax services were awarded either through a full competitive tender process or following an assessment of the
expertise of Ernst & Young compared with that of other potential service providers. These services are for a fixed term.
Under SEC regulations, the remuneration of the auditor of $53 million (2012 $54 million and 2011 $55 million) is required to be presented as follows:
audit $39 million (2012 $39 million and 2011 $41 million); other audit-related services $8 million (2012 $7 million and 2011 $6 million); tax $2 million
(2012 $4 million and 2011 $2 million); and all other fees $4 million (2012 $4 million and 2011 $6 million).
192
BP Annual Report and Form 20-F 2013
38. Subsidiaries, joint arrangements and associates
The more important subsidiaries, joint arrangements and associates of the group at 31 December 2013 and the group percentage of ordinary share
capital or joint arrangement interest (to nearest whole number) are set out below. Those held directly by the parent company are marked with an
asterisk (*), the percentage owned being that of the group unless otherwise indicated. The group has interests in a number of joint arrangements, but
none of these is individually material to the group. A complete list of investments in subsidiaries, joint arrangements and associates will be attached to
the parent company’s annual return made to the Registrar of Companies.
Subsidiaries
International
*BP Corporate Holdings
BP Exploration Operating Company
*BP Global Investments
*BP International
BP Oil International
*Burmah Castrol
Algeria
%
100
100
100
100
100
100
Country of
incorporation
England & Wales
England & Wales
England & Wales
England & Wales
England & Wales
Scotland
Principal activities
Investment holding
Exploration and production
Investment holding
Integrated oil operations
Integrated oil operations
Lubricants
BP Amoco Exploration (In Amenas)
100
Scotland
Exploration and production
Angola
BP Exploration (Angola)
Australia
BP Australia Capital Markets
BP Finance Australia
Azerbaijan
100
England & Wales
Exploration and production
100
100
Australia
Australia
Finance
Finance
BP Exploration (Caspian Sea)
100
England & Wales
Exploration and production
Brazil
BP Energy do Brazil
India
BP Exploration (Alpha)
New Zealand
BP Oil New Zealand
Norway
BP Norge
UK
BP Capital Markets
US
*BP Holdings North America
Atlantic Richfield Company
BP America
BP America Production Company
BP Company North America
BP Corporation North America
BP Exploration & Production
BP Exploration (Alaska)
BP Products North America
Standard Oil Company
BP Capital Markets America
Associates
Russia
Rosneft
100
Brazil
Exploration and production
100
England & Wales
Exploration and production
100
New Zealand
Marketing
100
Norway
Exploration and production
100
England & Wales
Finance
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
100
100
100
100
100
100
100
100
100
100
100
England & Wales
US
US
US
US
US
US
US
US
US
US
Country of
incorporation
%
Investment holding
Exploration and production, refining and marketing
pipelines and petrochemicals
Finance
Principal activities
20
Russia
Integrated oil operations
BP Annual Report and Form 20-F 2013
193
39. Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP Prudhoe
Bay Royalty Trust. The following financial information for BP p.l.c., 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 registered
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 accounted income of subsidiaries is the group’s share of profit related to such investments. The eliminations and
reclassifications column includes the necessary amounts to eliminate the intercompany balances and transactions between BP p.l.c., BP Exploration
(Alaska) Inc. and other subsidiaries. The financial information presented in the following tables for BP Exploration (Alaska) Inc. for all years includes
equity income arising from subsidiaries of BP Exploration (Alaska) Inc. some of which operate outside of Alaska and excludes the BP group’s
midstream operations in Alaska that are reported through different legal entities and that are included within the ‘other subsidiaries’ column in these
tables. BP p.l.c. also fully and unconditionally guarantees securities issued by BP Capital Markets p.l.c. and BP Capital Markets America Inc. These
companies are 100%- owned finance subsidiaries of BP p.l.c.
Income statement
For the year ended 31 December
Sales and other operating revenues
Earnings from joint ventures – after interest and tax
Earnings from associates – after interest and tax
Equity-accounted income of subsidiaries – after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
Fair value gain on embedded derivatives
Profit before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and other post-retirement
benefits
Profit before taxation
Taxation
Profit for the year
Attributable to
BP shareholders
Non-controlling interests
Statement of comprehensive income
For the year ended 31 December
Profit for the year
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
194
BP Annual Report and Form 20-F 2013
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
5,397
–
–
–
7
–
5,404
861
1,473
1,010
616
(68)
–
108
–
1,404
42
–
1,362
522
840
840
–
840
BP p.l.c.
–
–
–
24,693
118
–
24,811
–
–
–
–
–
–
1,234
–
23,577
43
81
23,453
2
23,451
23,451
–
23,451
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
840
–
840
840
–
840
BP p.l.c.
23,451
2,819
26,270
26,270
–
26,270
Other
subsidiaries
Eliminations and
reclassifications
379,136
447
2,742
–
841
13,115
396,281
302,887
26,054
6,037
12,894
2,029
3,441
11,728
(459)
31,670
1,172
399
30,099
5,939
24,160
23,853
307
24,160
(5,397)
–
–
(24,693)
(189)
–
(30,279)
(5,397)
–
–
–
–
–
–
–
(24,882)
(189)
–
(24,693)
–
(24,693)
(24,693)
–
(24,693)
Other
subsidiaries
Eliminations and
reclassifications
$ million
2013
BP group
379,136
447
2,742
–
777
13,115
396,217
298,351
27,527
7,047
13,510
1,961
3,441
13,070
(459)
31,769
1,068
480
30,221
6,463
23,758
23,451
307
23,758
$ million
2013
BP group
23,758
24,160
(3,711)
20,449
20,157
292
20,449
(24,693)
–
(892)
(24,693)
22,866
(24,693)
–
(24,693)
22,574
292
22,866
39. Condensed consolidating information on certain US subsidiaries – continued
Income statement continued
For the year ended 31 December
Sales and other operating revenues
Earnings from joint ventures – after interest and tax
Earnings from associates – after interest and tax
Equity-accounted income of subsidiaries – after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
Fair value gain on embedded derivatives
Profit before interest and taxation
Finance costs
Net finance expense relating to pensions and other post-retirement benefits
Profit before taxation
Taxation
Profit for the year
Attributable to
BP shareholders
Non-controlling interests
Statement of comprehensive income continued
For the year ended 31 December
Profit for the year
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
5,501
–
–
(59)
12
3,580
9,034
777
1,475
1,374
457
957
–
35
–
3,959
48
–
3,911
203
3,708
3,708
–
3,708
BP p.l.c.
–
–
–
12,649
187
–
12,836
–
–
–
–
–
–
1,766
–
11,070
43
103
10,924
(93)
11,017
11,017
–
11,017
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
3,708
–
BP p.l.c.
11,017
(232)
3,708
10,785
3,708
–
3,708
10,785
–
10,785
Other
subsidiaries
Eliminations and
reclassifications
375,765
260
3,675
–
1,764
6,697
388,161
297,498
32,451
6,784
12,230
5,318
1,475
11,641
(347)
21,111
1,182
463
19,466
6,770
12,696
12,462
234
12,696
(5,501)
–
–
(12,590)
(286)
(3,580)
(21,957)
(5,501)
–
–
–
–
–
(85)
–
(16,371)
(201)
–
(16,170)
–
(16,170)
(16,170)
–
(16,170)
Other
subsidiaries
Eliminations and
reclassifications
$ million
2012
BP group
375,765
260
3,675
–
1,677
6,697
388,074
292,774
33,926
8,158
12,687
6,275
1,475
13,357
(347)
19,769
1,072
566
18,131
6,880
11,251
11,017
234
11,251
$ million
2012
BP group
11,251
975
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
12,696
1,207
13,903
13,665
238
13,903
(16,170)
–
(16,170)
12,226
(16,170)
–
(16,170)
11,988
238
12,226
BP Annual Report and Form 20-F 2013
195
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
6,159
–
–
313
10
–
6,482
978
1,280
1,684
335
–
4
27
–
2,174
32
–
2,142
729
1,413
1,413
–
1,413
BP p.l.c.
–
–
–
26,019
242
1
26,262
–
–
–
–
–
–
1,048
–
25,214
47
(94)
25,261
49
25,212
25,212
–
25,212
Other
subsidiaries
Eliminations and
reclassifications
375,713
767
4,916
–
756
4,131
386,283
290,314
22,883
6,596
11,022
2,058
1,516
12,992
(68)
38,970
1,319
494
37,157
11,841
25,316
24,919
397
25,316
(6,159)
–
–
(26,332)
(320)
–
(32,811)
(6,159)
–
–
–
–
–
(109)
–
(26,543)
(211)
–
(26,332)
–
(26,332)
(26,332)
–
(26,332)
$ million
2011
BP group
375,713
767
4,916
–
688
4,132
386,216
285,133
24,163
8,280
11,357
2,058
1,520
13,958
(68)
39,815
1,187
400
38,228
12,619
25,609
25,212
397
25,609
$ million
2011
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
1,413
BP p.l.c.
25,212
Other
subsidiaries
25,316
Eliminations and
reclassifications
(26,332)
BP group
25,609
–
(3,674)
(938)
–
(4,612)
1,413
21,538
24,378
(26,332)
20,997
1,413
–
1,413
21,538
–
21,538
23,994
384
24,378
(26,332)
–
(26,332)
20,613
384
20,997
39. Condensed consolidating information on certain US subsidiaries – continued
Income statement continued
For the year ended 31 December
Sales and other operating revenues
Earnings from joint ventures – after interest and tax
Earnings from associates – after interest and tax
Equity-accounted income of subsidiaries – after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
Fair value gain on embedded derivatives
Profit before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and other post-retirement
benefits
Profit before taxation
Taxation
Profit for the year
Attributable to
BP shareholders
Non-controlling interests
Statement of comprehensive income continued
For the year ended 31 December
Profit for the year
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
196
BP Annual Report and Form 20-F 2013
39. Condensed consolidating information on certain US subsidiaries – continued
Balance sheet
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Subsidiaries – equity-accounted basis
Fixed assets
Loans
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan
deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Non-controlling interests
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
$ million
2013
BP group
133,690
12,181
22,039
9,199
16,636
1,565
–
195,310
763
5,985
3,509
922
985
1,376
–
–
–
–
–
–
(142,143)
(142,143)
(4,593)
–
–
–
–
–
(146,736)
208,850
–
–
(33,675)
–
–
–
–
–
(33,675)
–
216
29,231
39,831
2,675
1,388
512
467
22,520
96,840
–
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
8,546
–
417
–
–
–
–
8,963
–
–
–
22
–
–
8,985
–
152
9,593
–
18
–
–
–
9,763
–
–
–
–
–
2
–
142,143
142,145
–
–
–
–
–
1,020
143,165
–
–
21,550
–
–
–
–
6
21,556
–
125,144
12,181
21,622
9,199
16,634
1,565
–
186,345
5,356
5,985
3,509
900
985
356
203,436
216
29,079
42,363
2,675
1,370
512
467
22,514
99,196
–
9,763
21,556
18,748
164,721
99,196
302,632
(33,675)
96,840
(180,411)
305,690
889
–
171
–
166
1
1,227
–
1,227
9
–
–
–
1,659
1,942
–
3,610
4,837
2,727
–
1,540
–
–
–
4,267
–
4,267
4,584
–
58
–
–
–
–
4,642
8,909
13,911
155,812
13,911
–
13,911
155,812
–
155,812
77,218
2,322
7,249
7,381
1,779
5,044
100,993
–
100,993
4,756
2,225
489
40,811
15,780
24,973
9,778
98,812
199,805
102,827
101,722
1,105
102,827
(33,675)
–
–
–
–
–
(33,675)
–
(33,675)
(4,593)
–
–
–
–
–
47,159
2,322
8,960
7,381
1,945
5,045
72,812
–
72,812
4,756
2,225
547
40,811
17,439
26,915
–
9,778
(4,593)
102,471
(38,268)
175,283
(142,143)
130,407
(142,143)
–
(142,143)
129,302
1,105
130,407
BP Annual Report and Form 20-F 2013
197
39. Condensed consolidating information on certain US subsidiaries – continued
Balance sheet continued
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Subsidiaries – equity-accounted basis
Fixed assets
Loans
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Assets classified as held for sale
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Liabilities directly associated with assets classified as held for sale
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Non-controlling interests
198
BP Annual Report and Form 20-F 2013
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations and
reclassifications
$ million
2012
BP group
125,331
12,190
24,632
8,614
2,998
2,704
–
176,469
642
5,961
4,294
830
874
12
–
–
–
–
–
–
(136,553)
(136,553)
(4,282)
–
–
–
–
–
(140,835)
189,082
–
–
(34,728)
–
–
–
–
–
(34,728)
–
247
28,203
37,611
4,507
1,091
456
319
19,635
92,069
19,315
–
–
–
–
2
–
136,553
136,555
–
–
–
–
–
–
136,555
–
–
17,496
–
–
–
–
9
17,505
–
116,988
12,190
24,253
8,614
2,996
2,704
–
167,745
4,924
5,961
4,294
796
874
12
184,606
247
28,029
43,008
4,507
1,076
456
319
19,626
97,268
19,315
17,505
154,060
116,583
301,189
(34,728)
111,384
(175,563)
300,466
2,577
–
27
–
–
–
2,604
–
2,604
4,449
–
38
–
–
–
1,913
6,400
9,004
74,910
2,658
6,708
10,033
2,358
7,586
104,253
846
105,099
2,117
2,723
453
38,767
13,589
28,509
11,714
97,872
202,971
98,218
97,012
1,206
98,218
(34,728)
–
–
–
–
–
(34,728)
–
(34,728)
(4,282)
–
–
–
–
–
–
(4,282)
46,673
2,658
6,875
10,033
2,503
7,587
76,329
846
77,175
2,292
2,723
491
38,767
15,243
30,396
13,627
103,539
(39,010)
180,714
(136,553)
119,752
(136,553)
–
(136,553)
118,546
1,206
119,752
13,031
145,056
13,031
–
13,031
145,056
–
145,056
8,343
–
379
–
–
–
–
8,722
–
–
–
34
–
–
8,756
–
174
11,835
–
15
–
–
–
12,024
–
12,024
20,780
3,914
–
140
–
145
1
4,200
–
4,200
8
–
–
–
1,654
1,887
–
3,549
7,749
39. Condensed consolidating information on certain US subsidiaries – continued
Cash flow statement
For the year ended 31 December
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Currency translation differences relating to cash and cash equivalents
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
For the year ended 31 December
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Currency translation differences relating to cash and cash equivalents
Increase in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
For the year ended 31 December
Net cash provided by operating activities
Net cash used in investing activities
Net cash (used in) provided by financing activities
Currency translation differences relating to cash and cash equivalents
Decrease in cash and cash equivalents
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
746
(746)
–
–
–
–
–
BP p.l.c.
11,488
(690)
(10,801)
–
(3)
9
6
Other
subsidiaries
Eliminations and
reclassifications
25,094
(6,419)
(15,827)
40
2,888
19,626
22,514
(16,228)
–
16,228
–
–
–
–
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
681
(680)
–
–
1
(1)
–
BP p.l.c.
12,381
(7,060)
(5,312)
–
9
–
9
Issuer
Guarantor
BP
Exploration
(Alaska) Inc.
661
(661)
–
–
–
(1)
(1)
BP p.l.c.
8,321
(3,710)
(4,615)
–
(4)
4
–
Other
subsidiaries
Eliminations and
reclassifications
20,932
(5,335)
(10,213)
64
5,448
14,178
19,626
(13,515)
–
13,515
–
–
–
–
Other
subsidiaries
Eliminations and
reclassifications
25,178
(22,382)
(6,850)
(493)
(4,547)
18,725
14,178
(11,942)
–
11,942
–
–
–
–
$ million
2013
BP group
21,100
(7,855)
(10,400)
40
2,885
19,635
22,520
$ million
2012
BP group
20,479
(13,075)
(2,010)
64
5,458
14,177
19,635
$ million
2011
BP group
22,218
(26,753)
477
(493)
(4,551)
18,728
14,177
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2013
199
Supplementary information on oil and natural gas (unaudited)
2013 reserves and production information for equity-accounted entities includes BP’s share of TNK-BP from 1 January to 20 March, and Rosneft for
the period 21 March to 31 December. For the period 22 October 2012 to 31 December 2012, and throughout all of 2013, financial information for
equity-accounted entities does not include any information for TNK-BP, as equity accounting ceased on 22 October 2012. Comparative information
for 2012 and 2011 has been restated to reflect the adoption of IFRS 11 ‘Joint Arrangements’. For further information see Financial statements –
Note 1.
The regional analysis presented below is on a continent basis, with separate disclosure for countries that contain 15% or more of the total proved
reserves (for subsidiaries plus equity-accounted entities), in accordance with SEC and FASB requirements.
Oil and gas reserves – certain definitions
Unless the context indicates otherwise, the following terms have the meanings shown below:
Proved oil and gas reserves
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with
reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions,
operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates
that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the
hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i)
(ii)
The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any; and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain
economically producible oil or gas on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a
well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable
certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated
gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or
performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid
injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favourable than in the reservoir as a whole, the
operation of an installed programme in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes
the reasonable certainty of the engineering analysis on which the project or programme was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall
be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual
arrangements, excluding escalations based upon future conditions.
Undeveloped oil and gas reserves
Undeveloped oil and gas reserves are reserves of any category 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.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of
production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at
greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are
scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or
other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same
reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Developed oil and gas reserves
Developed oil and gas reserves are reserves of any category that can be expected to be recovered:
(i)
Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor
compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not
involving a well.
For details on BP’s proved reserves and production compliance and governance processes, see page 245.
200
BP Annual Report and Form 20-F 2013
Oil and natural gas exploration and production activities
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2013
Total
Subsidiariesa
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
29,314
316
29,630
18,707
10,923
10,040
195
10,235
3,650
75,313
6,816
82,129
38,236
6,585
43,893
2,501
2,408
4,909
193
4,716
8,809
3,366
12,175
5,063
35,720
5,079
40,799
20,082
7,112
20,717
Costs incurred for the year ended 31 Decemberb
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
–
–
–
178
1,942
2,120
–
–
–
14
455
469
1
158
159
1,291
4,877
6,327
Results of operations for the year ended 31 December
Sales and other operating revenuesd
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)e
Depreciation, depletion and
amortization
Impairments and (gains) losses on sale
of businesses and fixed assets
Profit (loss) before taxationf
Allocable taxes
Results of operations
1,129
1,661
2,790
280
1,102
(35)
(1,731)
504
118
238
2,552
554
1,998
183
1,280
1,463
17
430
–
86
934
14,047
14,981
437
3,691
1,112
3,241
490
3,268
15
(80)
1,038
11,669
425
475
(50)
3,312
1,204
2,108
–
–
–
194
569
763
5
12
17
28
42
–
55
–
–
125
(108)
(26)
(82)
7
284
291
951
683
1,925
2,413
1,154
3,567
1,477
892
184
322
–
30
30
883
2,755
3,668
3,195
6,518
9,713
387
1,623
–
89
559
3,132
129
3,563
4
642
(638)
29
5,260
4,453
1,925
2,528
Upstream, Rosneft and TNK-BP segments replacement cost profit before interest and tax
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
65
–
–
65
(65)
(2)
(63)
20,726
2,756
23,482
10,069
13,413
–
7
7
1,090
2,082
3,179
1,005
11,432
12,437
768
1,091
5,660
84
2,174
(16)
9,761
2,676
682
1,994
4,681
805
5,486
1,962
3,524
187,104
21,741
208,845
97,962
110,883
–
–
–
210
189
399
1,784
941
2,725
47
187
126
351
8
479
487
4,811
13,552
18,850
10,648
37,045
47,693
3,441
9,058
7,047
2,562
207
10,334
230
1,148
1,577
641
936
425
32,867
14,826
6,095
8,731
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Exploration and production activities –
subsidiaries (as above)
Midstream activities – subsidiariesg
TNK-BP – gain on sale
Equity-accounted entitiesh
Total replacement cost profit before
2,552
244
–
–
425
(40)
–
28
3,312
296
–
17
(108)
(14)
–
–
4
153
–
405
4,453
(154)
–
24
(65)
(4)
12,500
2,158
2,676
(29)
–
553
1,577
347
–
–
14,826
799
12,500
3,185
interest and tax
2,796
413
3,625
(122)
562
4,323
14,589
3,200
1,924
31,310
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries, which includes our share of oil and natural gas exploration and production activities of
joint operations. They do not include any costs relating to the Gulf of Mexico oil spill. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing
and export terminals and LNG processing facilities and transportation are excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada,
UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline,
the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes, other government take and the fair value gain on embedded derivatives of $459 million. The UK region includes a $1,055 million gain offset by corresponding charges primarily
in the US, relating to the group self-insurance programme.
f Excludes the unwinding of the discount on provisions and payables amounting to $141 million which is included in finance costs in the group income statement.
g Midstream and other activities excludes inventory holding gains and losses.
h The profits of equity-accounted entities are included after interest and tax.
BP Annual Report and Form 20-F 2013
201
Oil and natural gas exploration and production activities – continued
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Equity-accounted entities (BP share)b
Capitalized costs at 31 Decemberc
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
–
–
–
–
–
Costs incurred for the year ended 31 Decemberd
Acquisition of properties
Proved
Unproved
Exploration and appraisal costse
Development
Total costs
–
–
–
–
–
–
Results of operations for the year ended 31 December
Sales and other operating revenuesf
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and
amortization
Impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
Exploration and production activities –
equity-accounted entities after tax
(as above)
Midstream and other activities after
taxg
Total replacement cost profit after
interest and tax
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
28
28
17
17
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
7,648
29
7,677
3,282
4,395
–
–
–
8
714
722
2,294
–
2,294
–
586
630
6
317
–
1,539
755
460
295
295
110
405
Russiaa
Rest of
Asia
18,942
638
19,580
1,077
18,503
4,239
21
4,260
4,061
199
1,816
657
2,473
133
1,860
4,466
–
–
–
12
538
550
435
9,679
10,114
126
1,177
4,511
94
4,770
14
4,784
1
404
3,645
(1)
1,232
544
37
7,177
2,937
367
2,570
–
4,593
191
40
151
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
2,570
(412)
151
402
2,158
553
24
24
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
$ million
2013
Total
30,829
688
31,517
8,420
23,097
1,816
657
2,473
153
3,112
5,738
7,499
9,693
17,192
127
2,167
8,786
99
2,093
37
13,309
3,883
867
3,016
3,016
169
3,185
a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream
activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream
activities of TNK-BP and Rosneft are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities.
c Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
d The amounts shown reflect BP’s share of equity-accounted entities’ costs incurred, and not the costs incurred by BP in acquiring an interest in equity-accounted entities.
e Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
f Presented net of transportation costs and sales taxes.
g Includes interest, non-controlling interest and the net results of equity-accounted entities, and excludes inventory holding gains and losses.
202
BP Annual Report and Form 20-F 2013
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Subsidiariesa
Capitalized costs at 31 Decemberb j
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
28,370
400
28,770
19,002
9,768
9,421
199
9,620
3,161
6,459
70,133
7,084
77,217
35,459
41,758
1,928
2,244
4,172
197
3,975
8,153
3,590
11,743
4,444
32,755
4,524
37,279
16,901
7,299
20,378
Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc k
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
–
–
–
173
1,907
2,080
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and
amortization
Impairments and (gains) losses on sale
of businesses and fixed assets
Profit (loss) before taxationg
Allocable taxes
Results of operations
–
–
–
47
784
831
76
783
859
29
348
–
78
256
1,111
1,367
1,069
3,866
6,302
453
15,713
16,166
649
3,854
1,472
3,505
–
–
–
230
611
841
10
10
20
4
71
–
63
10
1,595
2,975
4,570
105
1,310
92
(1,474)
1,102
145
3,187
373
1,508
3,062
1,121
1,941
83
683
176
(313)
489
(3,576)
9,091
7,075
2,762
4,313
98
246
(226)
(67)
(159)
51
27
78
758
581
1,417
2,026
984
3,010
120
812
162
109
–
239
239
1,024
2,992
4,255
3,424
5,633
9,057
310
1,323
–
221
606
2,281
6
1,815
1,195
804
391
24
4,159
4,898
2,371
2,527
Africa
Asia
Australasia
$ million
2012
Total
Russia
Rest of
Asia
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
(330)
–
–
(330)
330
(13)
343
16,757
4,920
21,677
8,360
13,317
–
(68)
(68)
814
1,591
2,337
1,299
11,345
12,644
126
1,076
6,291
84
2,116
(2)
9,691
2,953
663
2,290
3,676
1,540
5,216
1,517
3,699
171,193
24,501
195,694
89,041
106,653
–
–
–
241
221
462
1,749
915
2,664
132
191
141
264
307
1,309
1,616
4,356
12,553
18,525
10,632
38,358
48,990
1,475
8,985
8,158
2,520
211
9,658
(5)
(2,999)
934
1,730
755
975
27,797
21,193
8,083
13,110
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Upstream segment and TNK-BP segment replacement cost profit before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream activities – subsidiariesh
Equity-accounted entitiesi
Total replacement cost profit before
3,062
(250)
–
176
(114)
35
7,075
(173)
16
(226)
774
–
1,195
163
160
4,898
(46)
48
330
11
3,005
2,953
32
640
1,730
370
–
21,193
767
3,904
interest and tax
2,812
97
6,918
548
1,518
4,900
3,346
3,625
2,100
25,864
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. They do not include any costs relating to the Gulf of Mexico oil spill or assets held for
sale. Midstream activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are
excluded. In addition, our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline
interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major
LNG activities are located in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $347 million. The UK region includes a $1,161 million gain offset by corresponding charges primarily
in the US, relating to the group self-insurance programme. The Russia region, for which equity accounting ceased on 22 October 2012, includes a net non-operating gain of $351 million including
dividend income of $709 million partly offset by a settlement charge of $325 million.
g Excludes the unwinding of the discount on provisions and payables amounting to $173 million which is included in finance costs in the group income statement.
h Midstream and other activities exclude inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and tax and the results exclude balances associated with assets held for sale.
j Excludes balances associated with assets held for sale.
k Excludes goodwill associated with business combinations.
BP Annual Report and Form 20-F 2013
203
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Equity-accounted entities (BP share)b
Capitalized costs at 31 Decemberc
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
–
–
–
–
–
Costs incurred for the year ended 31 Decemberc
Acquisition of propertiesd
Proved
Unproved
Exploration and appraisal costse
Development
Total costs
–
–
–
–
–
–
Results of operations for the year ended 31 December
Sales and other operating revenuesf
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and
amortization
Impairments and losses on sale of
businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
Exploration and production activities –
equity-accounted entities after tax
(as above)
Midstream and other activities after
taxg
Total replacement cost profit after
interest and tax
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
35
35
16
16
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
6,958
21
6,979
2,965
4,014
–
439
439
31
599
1,069
2,267
–
2,267
31
555
959
(11)
328
–
1,862
405
294
111
111
49
160
Africa
Asia
Australasia
Russiaa
Rest of
Asia
–
–
–
–
–
4,036
16
4,052
3,648
404
4
15
19
195
1,560
1,774
–
–
–
7
556
563
6,472
3,639
10,111
93
1,605
4,400
(24)
4,245
21
4,266
1
295
3,245
(2)
786
538
(27)
6,833
3,278
536
2,742
–
4,077
189
54
135
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
2,742
263
135
505
3,005
640
48
48
$ million
2012
Total
10,994
37
11,031
6,613
4,418
4
454
458
233
2,715
3,406
12,984
3,660
16,644
125
2,455
8,604
(37)
1,652
(27)
12,772
3,872
884
2,988
2,988
916
3,904
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
a The Russia region includes BP’s equity-accounted share of TNK-BP’s earnings. For 2012, equity-accounted earnings are included until 21 October 2012 only, after which our investment was classified
as an asset held for sale and therefore equity accounting ceased. The amounts shown exclude BP’s share of costs incurred and results of operations for the period 22 October to 31 December 2012.
b These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream
activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream
activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities.
c Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year. Capitalized costs exclude balances associated with assets held for sale.
d Includes costs capitalized as a result of asset exchanges.
e Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
f Presented net of transportation costs and sales taxes.
g Includes interest, non-controlling interest and the net results of equity-accounted entities, and excludes inventory holding gains and losses.
204
BP Annual Report and Form 20-F 2013
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Subsidiariesa
Capitalized costs at 31 Decemberb j
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
37,491
368
37,859
26,953
10,906
8,994
180
9,174
3,715
5,459
73,626
6,198
79,824
36,009
43,815
1,296
2,017
3,313
139
3,174
7,471
2,986
10,457
3,839
29,358
3,689
33,047
14,595
6,618
18,452
Costs incurred for the year ended 31 Decemberb j
Acquisition of propertiesc k
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
–
–
–
211
1,361
1,572
–
1
1
1
889
891
1,178
418
1,596
566
3,016
5,178
Results of operations for the year ended 31 December
1,997
3,495
5,492
37
1,372
72
(1,357)
–
1,273
1,273
1
230
–
101
751
19,089
19,840
1,065
3,402
1,854
4,688
874
199
2,980
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and
amortization
Impairments and (gains) losses on sale
of businesses and fixed assets
Profit (loss) before taxationg
Allocable taxes
Results of operations
237
2,592
2,829
271
405
3,505
2,263
1,409
3,672
35
503
278
935
–
679
679
490
2,933
4,102
3,353
4,858
8,211
163
1,146
–
215
8
–
8
132
227
367
25
20
45
9
66
–
62
6
Africa
Asia
Australasia
$ million
2011
Total
Russia
Rest of
Asia
–
–
–
–
–
–
–
–
6
–
6
–
–
–
6
4
–
72
14,833
4,495
19,328
6,235
13,093
1,733
3,008
4,741
511
1,340
6,592
1,450
10,811
12,261
134
787
5,956
118
3,370
1,279
4,649
1,294
3,355
176,439
21,212
197,651
92,779
104,872
–
–
–
225
251
476
1,611
967
2,578
70
194
147
257
3,156
6,698
9,854
2,413
10,422
22,689
11,450
41,922
53,372
1,520
7,704
8,307
5,091
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
523
1,668
–
1,692
172
8,114
26
1,024
4,468
2,483
1,985
(64)
(492)
467
806
384
422
13,497
6,343
2,152
4,191
15
158
(113)
(159)
46
(1,085)
1,189
2,483
1,205
1,278
18
3,210
5,001
2,184
2,817
(1)
81
(81)
(21)
(60)
(537)
8,150
4,111
1,001
3,110
–
840
1,738
677
1,061
(2,120)
28,616
24,756
9,906
14,850
Upstream segment and TNK-BP segment replacement cost profit before interest and tax
Exploration and production activities –
subsidiaries (as above)
Midstream activities – subsidiariesh
Equity-accounted entitiesi
Total replacement cost profit before
4,468
(118)
–
806
29
12
6,343
(157)
10
(113)
299
–
2,483
78
525
5,001
(4)
69
(81)
(1)
4,095
4,111
42
573
1,738
284
–
24,756
452
5,284
interest and tax
4,350
847
6,196
186
3,086
5,066
4,013
4,726
2,022
30,492
a These tables contain information relating to oil and natural gas exploration and production activities of subsidiaries. They do not include any costs relating to the Gulf of Mexico oil spill. Midstream
activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation are excluded. In addition,
our midstream activities of marketing and trading of natural gas, power and NGLs in the US, Canada, UK and Europe are excluded. The most significant midstream pipeline interests include the Trans-
Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline, the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located
in Trinidad, Indonesia and Australia and BP is also investing in the LNG business in Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $191 million. The UK region includes a $1,442 million gain offset by corresponding charges primarily
in the US, relating to the group self-insurance programme. The South America region includes a charge of $700 million associated with the termination of the agreement to sell our 60% interest in Pan
American Energy LLC to Bridas Corporation.
g Excludes the unwinding of the discount on provisions and payables amounting to $267 million which is included in finance costs in the group income statement.
h Midstream activities exclude inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and tax.
j Excludes balances associated with assets held for sale.
k Excludes goodwill associated with business combinations.
BP Annual Report and Form 20-F 2013
205
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Equity-accounted entities (BP share)a
Capitalized costs at 31 Decemberb
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
–
–
–
–
–
Costs incurred for the year ended 31 Decemberb
Acquisition of propertiesc
Proved
Unproved
Exploration and appraisal costsd
Development
Total costs
–
–
–
–
–
–
Results of operations for the year ended 31 December
Sales and other operating revenuese
Third parties
Sales between businesses
Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and
amortization
Impairments and (gains) losses on sale
of businesses and fixed assets
Profit (loss) before taxation
Allocable taxes
Results of operations
Exploration and production activities –
equity-accounted entities after tax
(as above)
Midstream and other activities after
taxf
Total replacement cost profit after
interest and tax
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
12
12
10
10
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
6,562
19
6,581
2,644
3,937
–
6
6
2
587
595
2,381
–
2,381
10
459
1,098
(239)
329
–
1,657
724
294
430
430
95
525
Africa
Asia
Australasia
Russia
Rest of
Asia
16,214
652
16,866
6,978
9,888
3,571
9
3,580
3,017
563
–
37
37
167
1,862
2,066
46
–
46
9
435
490
7,380
5,149
12,529
72
1,846
5,000
2
3,828
23
3,851
1
212
3,125
(1)
988
431
–
7,908
4,621
806
3,815
–
3,768
83
19
64
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
3,815
64
69
280
509
69
4,095
573
$ million
2011
Total
26,347
680
27,027
12,639
14,388
46
43
89
178
2,884
3,151
13,589
5,172
18,761
83
2,517
9,223
(238)
1,748
–
13,333
5,428
1,119
4,309
4,309
975
5,284
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
a These tables contain information relating to oil and natural gas exploration and production activities of equity-accounted entities. They do not include amounts relating to assets held for sale. Midstream
activities relating to the management and ownership of crude oil and natural gas pipelines, processing and export terminals and LNG processing facilities and transportation as well as downstream
activities of TNK-BP are excluded. The amounts reported for equity-accounted entities exclude the corresponding amounts for their equity-accounted entities.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes costs capitalized as a result of asset exchanges.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as incurred.
e Presented net of transportation costs and sales taxes.
f Includes interest, non-controlling interest and the net results of equity-accounted entities, and excludes inventory holding gains and losses
206
BP Annual Report and Form 20-F 2013
Movements in estimated net proved reserves
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
USb
Russia
Rest of
Asia
million barrels
2013
Total
Crude oila
Subsidiaries
At 1 January 2013
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionc
Sales of reserves-in-place
At 31 December 2013d
Developed
Undeveloped
Equity-accounted entities (BP share)e
At 1 January 2013
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2013f g
Developed
Undeveloped
242
431
673
(78)
12
–
–
(22)
(36)
(124)
169
380
549
–
–
–
–
–
–
–
–
–
–
–
–
–
170
79
249
(19)
–
–
–
(12)
–
(31)
163
55
218
1,443
989
2,432
(141)
52
–
4
(132)
(11)
(228)
1,297
907
2,204
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
1
–
–
–
–
–
1
–
1
1
–
–
–
–
1
1
22
32
54
30
1
–
–
(11)
–
20
29
45
74
339
351
690
(21)
27
34
12
(27)
(85)
(60)
316
314
630
361
383
744
345
359
704
312
255
567
26
2
–
–
(80)
–
(52)
320
195
515
12
11
23
(3)
–
–
–
–
–
(3)
10
10
20
324
266
590
330
205
535
–
–
–
–
–
–
–
–
–
–
–
–
–
2,492
1,962
4,454
384
–
4,579
228
(303)
(4,399)
489
3,064
1,879
4,943
2,492
1,962
4,454
3,064
1,879
4,943
268
137
405
65
65
–
39
(52)
–
117
320
202
522
198
13
211
1
–
–
–
(85)
–
(84)
120
7
127
466
150
616
440
209
649
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
52
45
97
(12)
–
–
3
(9)
–
(18)
57
22
79
–
–
–
–
–
–
–
–
–
–
–
–
–
52
45
97
57
22
79
2,509
1,968
4,477
(129)
132
–
46
(318)
(47)
(316)
2,355
1,806
4,161
3,041
2,337
5,378
362
27
4,613
240
(415)
(4,484)
343
3,510
2,211
5,721
5,550
4,305
9,855
5,865
4,017
9,882
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2013
Developed
Undeveloped
At 31 December 2013
Developed
Undeveloped
242
431
673
169
380
549
170
79
249
163
55
218
1,443
989
2,432
1,297
907
2,204
a Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production
and the option and ability to make lifting and sales arrangements independently.
b Proved reserves in the Prudhoe Bay field in Alaska include an estimated 72 million barrels 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 Excludes NGLs from processing plants in which an interest is held of 5,500 barrels per day.
d Includes 551 million barrels of NGLs. Also includes 21 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 131 million barrels of NGLs. Also includes 23 million barrels of crude oil in respect of the 0.47% non-controlling interest in Rosneft.
g Total proved liquid reserves held as part of our equity interest in Rosneft is 4,975 million barrels, comprising less than 1 mmboe in Vietnam and Canada, 32 million barrels in Venezuela and 4,943 million
barrels in Russia.
BP Annual Report and Form 20-F 2013
207
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russia
Rest of
Asia
billion cubic feet
2013
Total
Natural gasa
Subsidiaries
At 1 January 2013
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2013c
Developed
Undeveloped
Equity-accounted entities (BP share)d
At 1 January 2013
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2013e f
Developed
Undeveloped
1,038
666
1,704
340
141
481
8,245
2,986
11,231
(62)
49
9
–
(66)
(677)
(747)
643
314
957
(47)
–
–
–
(31)
–
(78)
364
39
403
(1,166)
630
–
39
(635)
(152)
(1,284)
7,122
2,825
9,947
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
3,588
6,250
9,838
1,139
1,923
3,062
62
144
–
–
(819)
–
(613)
(138)
28
–
55
(239)
–
(294)
3,109
6,116
9,225
961
1,807
2,768
–
–
–
–
–
–
–
–
–
–
–
–
–
1,276
904
2,180
175
164
339
2,617
1,759
4,376
3
64
14
51
(163)
(38)
(69)
29
–
–
–
(3)
–
26
685
–
8,871
254
(292)
(4,669)
4,849
1,364
747
2,111
230
135
365
4,171
5,054
9,225
926
413
1,339
2,148
94
–
1,875
(199)
(67)
3,851
1,519
3,671
5,190
128
18
146
1
3
33
–
(23)
(74)
(60)
72
14
86
4
–
4
10
–
–
–
(4)
–
6
10
–
10
–
–
–
1
–
–
–
–
–
1
–
1
1
4
–
4
10
1
11
3,282
2,323
5,605
18,562
14,702
33,264
(140)
–
–
511
(289)
–
82
667
945
9
2,480
(2,282)
(896)
923
3,932
1,755
5,687
17,660
16,527
34,187
–
–
–
–
–
–
–
–
–
–
–
–
–
4,196
2,845
7,041
719
67
8,918
305
(481)
(4,781)
4,747
5,837
5,951
11,788
22,758
17,547
40,305
23,497
22,478
45,975
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2013
Developed
Undeveloped
At 31 December 2013
Developed
Undeveloped
1,038
666
1,704
643
314
957
340
141
481
364
39
403
8,245
2,986
11,231
7,122
2,825
9,947
4,864
7,154
12,018
4,473
6,863
11,336
1,314
2,087
3,401
1,191
1,942
3,133
2,617
1,759
4,376
4,171
5,054
9,225
1,054
431
1,485
1,591
3,685
5,276
3,282
2,323
5,605
3,932
1,755
5,687
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Includes 180 billion cubic feet of natural gas consumed in operations, 149 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities.
c Includes 2,685 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
d Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
e Includes 41 billion cubic feet of natural gas in respect of the 0.44% non-controlling interest in Rosneft.
f Total proved gas reserves held as part of our equity interest in Rosneft is 9,271 billion cubic feet, comprising 1 billion cubic feet in Canada, 14 billion cubic feet in Venezuela, 31 billion cubic feet in
Vietnam and 9,225 billion cubic feet in Russia.
208
BP Annual Report and Form 20-F 2013
Movements in estimated net proved reserves – continued
Bitumena
Subsidiaries
At 1 January 2013
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2013
Developed
Undeveloped
million barrels
2013
Total
–
195
195
(7)
–
–
–
–
–
(7)
–
188
188
Rest of
North
America
–
195
195
(7)
–
–
–
–
–
(7)
–
188
188
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2013
209
Movements in estimated net proved reserves – continued
Total hydrocarbonsa
Subsidiaries
At 1 January 2013
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond e
Sales of reserves-in-place
At 31 December 2013f
Developed
Undeveloped
Equity-accounted entities (BP share)g
At 1 January 2013
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place
At 31 December 2013h i
Developed
Undeveloped
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
USc
Russia
Rest of
Asia
2013
Total
million barrels of oil equivalentb
2,865
1,504
4,369
1
195
196
640
1,110
1,750
508
587
1,095
421
546
967
(89)
20
2
–
(34)
(152)
(253)
280
434
714
–
–
–
–
–
–
–
–
–
–
–
–
–
229
103
332
(27)
–
–
–
(18)
–
(45)
225
62
287
–
–
–
–
–
–
–
–
–
–
–
–
–
(342)
161
–
10
(241)
(38)
(450)
2,525
1,394
3,919
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
427
209
636
435
81
–
363
(86)
(12)
781
618
445
5,709
4,699
1,063
10,408
(36)
–
–
91
(59)
–
(4)
(20)
294
2
473
(712)
(202)
(165)
582
835
1,417
735
324
5,399
4,844
1,059
10,243
2,943
2,265
5,208
502
–
6,108
272
(353)
(5,204)
1,325
3,782
2,751
6,533
2,943
2,265
5,208
3,782
2,751
6,533
220
15
235
1
1
6
–
(88)
(13)
(93)
133
9
142
647
224
871
715
844
–
–
–
–
–
–
–
–
–
–
–
–
–
3,765
2,827
6,592
486
39
6,150
292
(497)
(5,309)
1,161
4,517
3,236
7,753
618
445
9,474
7,526
1,063
17,000
735
324
9,916
8,080
1,559
1,059
17,996
(5)
–
–
–
(1)
–
(6)
2
188
190
–
–
–
1
–
–
–
–
–
1
–
1
1
1
195
196
2
189
191
41
25
–
–
(152)
–
(86)
564
1,100
1,664
559
508
1,067
(20)
38
36
20
(55)
(92)
(73)
552
442
994
1,199
1,618
2,817
1,116
1,542
2,658
3
7
–
9
(121)
–
(102)
486
507
993
43
39
82
2
–
–
–
(1)
–
1
50
33
83
551
626
1,177
536
540
1,076
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2013
Developed
Undeveloped
At 31 December 2013
Developed
Undeveloped
421
546
967
280
434
714
229
103
332
225
62
287
2,865
1,504
4,369
2,525
1,394
3,919
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 72 million barrels of oil equivalent 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.
d Excludes NGLs from processing plants in which an interest is held of 5,500 barrels of oil equivalent per day.
e Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 26 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted entities.
f Includes 551 million barrels of NGLs. Also includes 484 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 131 million barrels of NGLs. Also includes 30 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft.
i Total proved reserves held as part of our equity interest in Rosneft is 6,574 million barrels of oil equivalent, comprising 1 million barrels of oil equivalent in Canada, 34 million barrels of oil equivalent in
Venezuela, 5 million barrels of oil equivalent in Vietnam and 6,533 million barrels of oil equivalent in Russia.
210
BP Annual Report and Form 20-F 2013
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
USb
Rest of
North
America
Russia
Rest of
Asia
million barrels
2012
Total
Crude oila
Subsidiaries
At 1 January 2012
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionc
Sales of reserves-in-place
At 31 December 2012d h
Developed
Undeveloped
Equity-accounted entities (BP share)e
At 1 January 2012
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2012f g i
Developed
Undeveloped
288
445
733
(30)
3
4
–
(31)
(6)
(60)
242
431
673
–
–
–
–
–
–
–
–
–
–
–
–
–
69
230
299
(25)
–
–
1
(8)
(18)
(50)
170
79
249
1,685
1,173
2,858
(280)
140
21
23
(142)
(188)
(426)
1,443
989
2,432
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
27
48
75
(11)
–
–
–
(10)
–
(21)
22
32
54
349
348
697
(2)
24
–
–
(29)
–
(7)
339
351
690
376
396
772
361
383
744
311
315
626
(1)
13
–
2
(73)
–
(59)
312
255
567
–
14
14
9
–
–
–
–
–
9
12
11
23
311
329
640
324
266
590
–
–
–
–
–
–
–
–
–
–
–
–
–
2,596
1,613
4,209
462
47
–
67
(316)
(15)
245
2,492
1,962
4,454
2,596
1,613
4,209
2,492
1,962
4,454
177
279
456
(2)
2
–
–
(51)
–
(51)
268
137
405
256
58
314
(23)
–
–
–
(80)
–
(103)
198
13
211
433
337
770
466
150
616
59
47
106
2,616
2,537
5,153
–
–
–
–
(9)
–
(9)
52
45
97
–
–
–
–
–
–
–
–
–
–
–
–
–
(349)
158
25
26
(324)
(212)
(676)
2,509
1,968
4,477
3,201
2,033
5,234
446
71
–
67
(425)
(15)
144
3,041
2,337
5,378
59
47
5,817
4,570
106
10,387
52
45
97
5,550
4,305
9,855
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2012
Developed
Undeveloped
At 31 December 2012
Developed
Undeveloped
288
445
733
242
431
673
69
230
299
170
79
249
1,685
1,173
2,858
1,443
989
2,432
a Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production
and the option and ability to make lifting and sales arrangements independently.
b Proved reserves in the Prudhoe Bay field in Alaska include an estimated 76 million barrels 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 Excludes NGLs from processing plants in which an interest is held of 13,500 barrels per day.
d Includes 591 million barrels of NGLs. Also includes 14 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 103 million barrels of NGLs. Also includes 328 million barrels of crude oil in respect of the 7.35% non-controlling interest in TNK-BP.
g Total proved liquid reserves held as part of our equity interest in TNK-BP is 4,540 million barrels, comprising 87 million barrels in Venezuela and 4,454 million barrels in Russia.
h Includes assets held for sale of 39 million barrels.
i Includes assets held for sale of 4,540 million barrels.
BP Annual Report and Form 20-F 2013
211
Movements in estimated net proved reserves – continued
Natural gasa
Subsidiaries
At 1 January 2012
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2012c g
Developed
Undeveloped
Equity-accounted entities (BP share)d
At 1 January 2012
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2012e f h
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Africa
Asia
Australasia
billion cubic feet
2012
Total
Russia
Rest of
Asia
1,411
909
2,320
43
450
493
9,721
3,831
13,552
(18)
95
17
–
(164)
(546)
(616)
(13)
–
(1)
7
(5)
–
(12)
(1,853)
885
232
225
(661)
(1,149)
(2,321)
1,038
666
1,704
340
141
481
8,245
2,986
11,231
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
28
–
28
(19)
–
–
–
(5)
–
(24)
4
–
4
–
–
–
–
–
–
–
–
–
–
–
–
–
28
–
28
4
–
4
2,869
6,529
9,398
1,224
2,033
3,257
(116)
756
–
598
(775)
(23)
440
(14)
69
–
1
(251)
–
(195)
3,588
6,250
9,838
1,139
1,923
3,062
1,144
1,006
2,150
86
110
–
3
(169)
–
30
1,276
904
2,180
–
195
195
144
–
–
–
–
–
144
175
164
339
4,013
7,535
11,548
4,864
7,154
12,018
1,224
2,228
3,452
1,314
2,087
3,401
–
–
–
–
–
–
–
–
–
–
–
–
–
2,119
659
2,778
569
–
–
1,310
(280)
(1)
1,598
2,617
1,759
4,376
2,119
659
2,778
2,617
1,759
4,376
1,034
364
1,398
38
156
–
–
(253)
–
(59)
926
413
1,339
104
51
155
25
1
–
–
(35)
–
(9)
128
18
146
1,138
415
1,553
1,054
431
1,485
3,570
2,365
5,935
19,900
16,481
36,381
(41)
–
–
–
(289)
–
(330)
(2,036)
1,961
248
831
(2,403)
(1,718)
(3,117)
3,282
2,323
5,605
18,562
14,702
33,264
–
–
–
–
–
–
–
–
–
–
–
–
–
3,367
1,911
5,278
824
111
–
1,313
(484)
(1)
1,763
4,196
2,845
7,041
3,570
2,365
5,935
3,282
2,323
5,605
23,267
18,392
41,659
22,758
17,547
40,305
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2012
Developed
Undeveloped
At 31 December 2012
Developed
Undeveloped
1,411
909
2,320
1,038
666
1,704
43
450
493
340
141
481
9,721
3,831
13,552
8,245
2,986
11,231
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Includes 190 billion cubic feet of natural gas consumed in operations, 145 billion cubic feet in subsidiaries, 45 billion cubic feet in equity-accounted entities and excludes 9 billion cubic feet of produced
non-hydrocarbon components that meet regulatory requirements for sales.
c Includes 2,890 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
d Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
e Includes 270 billion cubic feet of natural gas in respect of the 6.17% non-controlling interest in TNK-BP.
f Total proved gas reserves held as part of our equity interest in TNK-BP is 4,492 billion cubic feet, comprising 38 billion cubic feet in Venezuela, 78 billion cubic feet in Vietnam and 4,376 billion cubic feet
in Russia.
g Includes assets held for sale of 590 billion cubic feet.
h Includes assets held for sale of 4,492 billion cubic feet.
212
BP Annual Report and Form 20-F 2013
Movements in estimated net proved reserves – continued
Bitumena
Subsidiaries
At 1 January 2012
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2012
Developed
Undeveloped
million barrels
2012
Total
–
178
178
17
–
–
–
–
–
17
–
195
195
Rest of
North
America
–
178
178
17
–
–
–
–
–
17
–
195
195
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2013
213
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
2012
Total
million barrels of oil equivalentb
Total hydrocarbonsa
Subsidiaries
At 1 January 2012
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond e
Sales of reserves-in-place
At 31 December 2012f j
Developed
Undeveloped
Equity-accounted entities (BP share)g
At 1 January 2012
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond e
Sales of reserves-in-place
At 31 December 2012h i k
Developed
Undeveloped
531
602
1,133
(33)
19
7
–
(59)
(100)
(166)
421
546
967
76
308
384
(27)
–
–
2
(9)
(18)
(52)
229
103
332
3,362
1,833
5,195
(600)
293
61
62
(256)
(386)
(826)
2,865
1,504
4,369
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
5
178
183
14
–
–
–
(1)
–
13
1
195
196
–
–
–
–
–
–
–
–
–
–
–
–
–
522
1,173
1,695
522
665
1,187
(31)
130
–
103
(143)
(4)
55
(3)
25
–
2
(116)
–
(92)
640
1,110
1,750
508
587
1,095
546
522
1,068
13
43
–
1
(58)
–
(1)
559
508
1,067
1,068
1,695
2,763
1,199
1,618
2,817
–
48
48
34
–
–
–
–
–
34
43
39
82
522
713
1,235
551
626
1,177
–
–
–
–
–
–
–
–
–
–
–
–
–
2,961
1,727
4,688
560
47
–
292
(364)
(15)
520
2,943
2,265
5,208
2,961
1,727
4,688
2,943
2,265
5,208
355
342
697
5
29
–
–
(95)
–
(61)
427
209
636
274
66
340
(19)
–
–
–
(86)
–
(105)
220
15
235
675
455
6,048
5,556
1,130
11,604
(8)
–
–
–
(59)
–
(67)
(683)
496
68
169
(738)
(508)
(1,196)
618
445
5,709
4,699
1,063
10,408
–
–
–
–
–
–
–
–
–
–
–
–
–
3,781
2,363
6,144
588
90
–
293
(508)
(15)
448
3,765
2,827
6,592
629
408
1,037
647
224
871
675
455
9,829
7,919
1,130
17,748
618
445
9,474
7,526
1,063
17,000
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2012
Developed
Undeveloped
At 31 December 2012
Developed
Undeveloped
531
602
1,133
421
546
967
76
308
384
229
103
332
3,362
1,833
5,195
2,865
1,504
4,369
5
178
183
1
195
196
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 76 million barrels of oil equivalent 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.
d Excludes NGLs from processing plants in which an interest is held of 13,500 barrels of oil equivalent per day.
e Includes 33 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 8 million barrels of oil equivalent in equity-accounted entities and
excludes 2 million barrels of oil equivalent of produced non-hydrocarbon components that meet regulatory requirements for sales.
f Includes 591 million barrels of NGLs. Also includes 512 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 103 million barrels of NGLs. Also includes 374 million barrels of oil equivalent in respect of the non-controlling interest in TNK-BP.
i Total proved reserves held as part of our equity interest in TNK-BP is 5,315 million barrels of oil equivalent, comprising 93 million barrels of oil equivalent in Venezuela, 14 million barrels of oil equivalent
in Vietnam and 5,208 million barrels of oil equivalent in Russia.
j Includes assets held for sale of 140 million barrels of oil equivalent.
k Includes assets held for sale of 5,315 million barrels of oil equivalent.
214
BP Annual Report and Form 20-F 2013
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
USb
Rest of
North
America
Russia
Rest of
Asia
million barrels
2011
Total
Crude oila
Subsidiaries
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionc
Sales of reserves-in-place
At 31 December 2011d
Developed
Undeveloped
Equity-accounted entities (BP share)e
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2011f g
Developed
Undeveloped
364
431
795
(1)
14
–
–
(41)
(34)
(62)
288
445
733
–
–
–
–
–
–
–
–
–
–
–
–
–
77
221
298
5
8
–
–
(12)
–
1
69
230
299
1,729
1,190
2,919
27
97
10
1
(162)
(34)
(61)
1,685
1,173
2,858
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
44
58
102
6
1
7
1
(13)
(29)
(27)
27
48
75
408
407
815
(12)
70
98
–
(30)
(244)
(118)
349
348
697
452
465
917
376
396
772
371
374
745
(68)
10
–
19
(68)
(12)
(119)
311
315
626
–
12
12
2
–
–
–
–
–
2
–
14
14
371
386
757
311
329
640
–
–
–
–
–
–
–
–
–
–
–
–
–
2,388
1,362
3,750
677
73
–
25
(316)
–
459
2,596
1,613
4,209
2,388
1,362
3,750
2,596
1,613
4,209
269
325
594
(131)
70
4
–
(50)
(31)
(138)
177
279
456
370
24
394
(5)
–
1
–
(76)
–
(80)
256
58
314
639
349
988
433
337
770
48
58
106
2,902
2,657
5,559
3
6
–
–
(9)
–
–
59
47
106
–
–
–
–
–
–
–
–
–
–
–
–
–
(159)
206
21
21
(355)
(140)
(406)
2,616
2,537
5,153
3,166
1,805
4,971
662
143
99
25
(422)
(244)
263
3,201
2,033
5,234
48
58
106
59
47
6,068
4,462
10,530
5,817
4,570
106
10,387
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2011
Developed
Undeveloped
At 31 December 2011
Developed
Undeveloped
364
431
795
288
445
733
77
221
298
69
230
299
1,729
1,190
2,919
1,685
1,173
2,858
a Crude oil includes NGLs and condensate. Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production
and the option and ability to make lifting and sales arrangements independently.
b Proved reserves in the Prudhoe Bay field in Alaska include an estimated 82 million barrels 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 Excludes NGLs from processing plants in which an interest is held of 28 thousand barrels per day.
d Includes 616 million barrels of NGLs. Also includes 20 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 19 million barrels of NGLs. Also includes 310 million barrels of crude oil in respect of the 7.37% non-controlling interest in TNK-BP.
g Total proved liquid reserves held as part of our equity interest in TNK-BP is 4,305 million barrels, comprising 95 million barrels in Venezuela, one million barrels in Vietnam and 4,209 million barrels in
Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated by evidence of Russian subsoil law, track
record of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved liquid reserves of 221 million barrels.
BP Annual Report and Form 20-F 2013
215
Movements in estimated net proved reserves – continued
Natural gasa
Subsidiaries
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2011c
Developed
Undeveloped
Equity-accounted entities (BP share)d
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionb
Sales of reserves-in-place
At 31 December 2011e f
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
US
South
America
Africa
Asia
Australasia
billion cubic feet
2011
Total
Russia
Rest of
Asia
1,416
829
2,245
40
430
470
9,495
4,248
13,743
169
56
8
–
(146)
(12)
75
30
1
–
–
(8)
–
23
–
597
93
219
(737)
(363)
(191)
1,411
909
2,320
43
450
493
9,721
3,831
13,552
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
58
–
58
(9)
–
7
–
(5)
(23)
(30)
28
–
28
–
–
–
–
–
–
–
–
–
–
–
–
–
58
–
58
28
–
28
3,575
6,575
10,150
1,329
2,351
3,680
202
84
–
47
(811)
(274)
(752)
(206)
15
–
–
(232)
–
(423)
2,869
6,529
9,398
1,224
2,033
3,257
–
–
–
–
–
–
–
–
–
–
–
–
–
1,075
1,192
2,267
–
175
175
1,900
459
2,359
(75)
190
31
–
(167)
(96)
(117)
20
–
–
–
–
–
20
683
–
–
–
(264)
–
419
1,144
1,006
2,150
–
195
195
2,119
659
2,778
1,290
268
1,558
69
28
310
–
(244)
(323)
(160)
1,034
364
1,398
71
19
90
(3)
12
76
–
(20)
–
65
104
51
155
3,563
2,342
5,905
20,766
17,043
37,809
299
22
–
–
(291)
–
30
554
803
418
266
(2,474)
(995)
(1,428)
3,570
2,365
5,935
19,900
16,481
36,381
–
–
–
–
–
–
–
–
–
–
–
–
–
3,046
1,845
4,891
625
202
107
–
(451)
(96)
387
3,367
1,911
5,278
4,650
7,767
12,417
4,013
7,535
11,548
1,329
2,526
3,855
1,224
2,228
3,452
1,900
459
2,359
2,119
659
2,778
1,361
287
1,648
1,138
415
1,553
3,563
2,342
5,905
3,570
2,365
5,935
23,812
18,888
42,700
23,267
18,392
41,659
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2011
Developed
Undeveloped
At 31 December 2011
Developed
Undeveloped
1,416
829
2,245
1,411
909
2,320
40
430
470
43
450
493
9,495
4,248
13,743
9,721
3,831
13,552
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b Includes 196 billion cubic feet of natural gas consumed in operations,155 billion cubic feet in subsidiaries, 41 billion cubic feet in equity-accounted entities and excludes 14 billion cubic feet of produced
non-hydrocarbon components which meet regulatory requirements for sales.
c Includes 2,759 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
d Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
e Includes 174 billion cubic feet of natural gas in respect of the 6.27% non-controlling interest in TNK-BP.
f Total proved gas reserves held as part of our equity interest in TNK-BP is 2,881 billion cubic feet, comprising 30 billion cubic feet in Venezuela, 73 billion cubic feet in Vietnam and 2,778 billion cubic feet
in Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence renewals is demonstrated by evidence of Russian subsoil law, track
record of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase in proved gas reserves of 185 billion cubic feet.
216
BP Annual Report and Form 20-F 2013
Movements in estimated net proved reserves – continued
Bitumena
Subsidiaries
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 December 2011
Developed
Undeveloped
million barrels
2011
Total
–
179
179
(1)
–
–
–
–
–
(1)
–
178
178
Rest of
North
America
–
179
179
(1)
–
–
–
–
–
(1)
–
178
178
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2013
217
Movements in estimated net proved reserves – continued
Total hydrocarbonsa
Subsidiaries
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond e
Sales of reserves-in-place
At 31 December 2011f
Developed
Undeveloped
Equity-accounted entities (BP share)g
At 1 January 2011
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond e
Sales of reserves-in-place
At 31 December 2011h i
Developed
Undeveloped
Europe
UK
Rest of
Europe
North
America
Rest of
North
America
USc
South
America
Africa
Asia
Australasia
2011
Total
million barrels of oil equivalentb
Russia
Rest of
Asia
608
574
1,182
28
24
1
–
(66)
(36)
(49)
531
602
1,133
–
–
–
–
–
–
–
–
–
–
–
–
–
84
295
379
10
8
–
–
(13)
–
5
76
308
384
–
–
–
–
–
–
–
–
–
–
–
–
–
3,366
1,923
5,289
10
179
189
660
1,192
1,852
600
779
1,379
27
200
26
39
(289)
(97)
(94)
(3)
–
2
–
(1)
(4)
(6)
41
15
7
9
(153)
(76)
(157)
(103)
12
–
19
(108)
(12)
(192)
3,362
1,833
5,195
5
178
183
522
1,173
1,695
522
665
1,187
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
593
613
1,206
(25)
103
103
–
(59)
(260)
(138)
546
522
1,068
1,253
1,805
3,058
1,068
1,695
2,763
–
43
43
5
–
–
–
–
–
5
–
48
48
600
822
1,422
522
713
1,235
–
–
–
–
–
–
–
–
–
–
–
–
–
2,716
1,441
4,157
795
73
–
25
(362)
–
531
2,961
1,727
4,688
2,716
1,441
4,157
2,961
1,727
4,688
491
371
862
(119)
75
58
–
(92)
(87)
(165)
355
342
697
382
27
409
(5)
2
14
–
(80)
–
(69)
274
66
340
662
462
6,481
5,775
1,124
12,256
55
10
–
–
(59)
–
6
(64)
344
94
67
(781)
(312)
(652)
675
455
6,048
5,556
1,130
11,604
–
–
–
–
–
–
–
–
–
–
–
–
–
3,691
2,124
5,815
770
178
117
25
(501)
(260)
329
3,781
2,363
6,144
873
398
1,271
629
408
1,037
662
462
1,124
10,172
7,899
18,071
675
455
9,829
7,919
1,130
17,748
Total subsidiaries and equity-accounted entities (BP share)
At 1 January 2011
Developed
Undeveloped
At 31 December 2011
Developed
Undeveloped
608
574
1,182
531
602
1,133
84
295
379
76
308
384
3,366
1,923
5,289
3,362
1,833
5,195
10
179
189
5
178
183
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting
and sales arrangements independently.
b 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 82 million barrels of oil equivalent 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.
d Excludes NGLs from processing plants in which an interest is held of 28 thousand barrels of oil equivalent a day.
e Includes 34 million barrels of oil equivalent of natural gas consumed in operations, 27 million barrels of oil equivalent in subsidiaries, seven million barrels of oil equivalent in equity-accounted entities
and excludes two million barrels of oil equivalent of produced non-hydrocarbon components which meet regulatory requirements for sales.
f Includes 616 million barrels of NGLs. Also includes 496 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 19 million barrels of NGLs. Also includes 340 million barrels of oil equivalent in respect of the non-controlling interest in TNK-BP.
i Total proved reserves held as part of our equity interest in TNK-BP is 4,802 million barrels of oil equivalent, comprising 100 million barrels of oil equivalent in Venezuela, 14 million barrels of oil
equivalent in Vietnam and 4,688 million barrels of oil equivalent in Russia. In 2011, BP aligned its reporting with TNK-BP by moving to a life of field reporting basis. Reasonable certainty of licence
renewals is demonstrated by evidence of Russian subsoil law, track record of renewals within the industry and track record of success in obtaining renewals by TNK-BP. This has resulted in an increase
in proved reserves of 253 million barrels of oil equivalent.
218
BP Annual Report and Form 20-F 2013
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 measure 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 FASB Oil and Gas Disclosures requirements.
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 average crude oil and natural gas prices and exchange rates from
the previous 12 months. Furthermore, both proved reserves 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
the assumptions on which it is based and its lack of comparability with the historical cost information presented in the financial statements.
Europe
Rest of
Europe
UK
South
America
North
America
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2013
Total
Russia
Rest of
Asia
At 31 December 2013
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
66,200
21,900
6,500
23,900
13,900
6,800
26,300
11,200
2,000
8,000
5,100
2,200
234,500
99,000
27,700
37,000
70,800
34,300
9,400
4,600
2,000
400
2,400
1,900
40,000
11,600
7,600
11,100
9,700
4,200
67,500
17,800
10,900
14,300
24,500
9,300
Standardized measure of discounted
future net cash flowse
7,100
2,900
36,500
500
5,500
15,200
–
–
–
–
–
–
–
89,000
35,000
23,700
6,200
24,100
13,300
57,600
20,000
6,900
8,100
22,600
12,800
590,500
221,100
87,300
109,000
173,100
84,800
10,800
9,800
88,300
Equity-accounted entities (BP share)f
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
45,800
22,500
6,000
5,900
11,400
6,900
4,500
–
–
–
–
–
–
–
255,600
139,000
19,700
15,200
81,700
48,700
14,300
11,800
2,100
100
300
100
33,000
200
–
–
–
–
–
–
–
315,700
173,300
27,800
21,200
93,400
55,700
37,700
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
future net cash flows
7,100
2,900
36,500
500
10,000
15,200
33,000
11,000
9,800
126,000
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeari
Subsidiaries
Equity-accounted
entities (BP share)
$ million
Total subsidiaries and
equity-accounted
entities
(30,600)
14,000
1,900
(1,800)
(3,100)
12,900
(4,100)
(3,500)
9,300
(5,000)
(7,900)
3,200
2,000
(100)
(400)
3,400
(2,100)
9,000
2,800
9,900
(38,500)
17,200
3,900
(1,900)
(3,500)
16,300
(6,200)
5,500
12,100
4,900
a The marker prices used were Brent $108.02/bbl, Henry Hub $3.66/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
c Taxation is computed using appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e Non-controlling interest in BP Trinidad and Tobago LLC amounted to $1,700 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
g Non-controlling interest in Rosneft amounted to $200 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements.
BP Annual Report and Form 20-F 2013
219
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserve – continued
Europe
UK
Rest of
Europe
South
America
North
America
Rest of
North
America
US
Africa
Asia
Australasia
$ million
2012
Total
Russia
Rest of
Asia
At 31 December 2012
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
88,000
24,600
7,400
35,200
20,800
10,900
30,800
10,400
2,400
11,700
6,300
2,400
261,100
117,000
29,600
40,700
73,800
40,100
9,500
4,600
2,400
400
2,100
2,000
30,400
10,700
7,700
6,300
5,700
2,700
75,800
17,200
13,000
17,500
28,100
10,900
Standardized measure of discounted
future net cash flowse
9,900
3,900
33,700
100
3,000
17,200
–
–
–
–
–
–
–
54,200
14,000
10,900
6,900
22,400
8,300
54,300
19,000
3,700
8,400
23,200
11,800
604,100
217,500
77,100
127,100
182,400
89,100
14,100
11,400
93,300
Equity-accounted entities (BP share)f
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
49,400
24,800
5,500
6,600
12,500
7,600
4,900
–
–
–
–
–
–
–
203,600
133,400
16,600
10,100
43,500
21,600
24,400
21,000
1,900
200
1,300
300
21,900
1,000
–
–
–
–
–
–
–
277,400
179,200
24,000
16,900
57,300
29,500
27,800
future net cash flowsi
9,900
3,900
33,700
100
7,900
17,200
21,900
15,100
11,400
121,100
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yearj
Subsidiaries
Equity-accounted
entities (BP share)
$ million
Total subsidiaries and
equity-accounted
entities
(34,600)
14,400
8,000
(15,300)
(16,000)
23,200
(7,700)
(6,800)
11,600
(23,200)
(8,300)
3,100
1,200
2,900
(1,000)
300
(500)
(100)
2,800
400
(42,900)
17,500
9,200
(12,400)
(17,000)
23,500
(8,200)
(6,900)
14,400
(22,800)
a The marker prices used were Brent $111.13/bbl, Henry Hub $2.75/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
c Taxation is computed using appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e Non-controlling interest in BP Trinidad and Tobago LLC amounted to $900 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
g Non-controlling interest in TNK-BP amounted to $1,600 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Includes future net cash flows for assets held for sale at 31 December 2012.
j Total change in the standardized measure during the year includes the effect of exchange rate movements.
220
BP Annual Report and Form 20-F 2013
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserve – continued
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2011
Total
At 31 December 2011
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
97,900
30,500
8,500
37,100
21,800
11,200
36,400
10,900
2,700
15,200
7,600
3,100
332,900
140,700
32,300
57,000
102,900
55,500
9,200
3,200
1,900
900
3,200
2,800
39,100
10,500
7,600
11,400
9,600
4,100
82,100
16,800
13,200
19,800
32,300
12,500
Standardized measure of discounted
future net cash flowse
10,600
4,500
47,400
400
5,500
19,800
–
–
–
–
–
–
–
59,200
16,000
9,600
8,100
25,500
9,800
53,900
15,600
3,200
9,000
26,100
13,500
710,700
244,200
79,000
158,500
229,000
112,500
15,700
12,600
116,500
Equity-accounted entities (BP share)f
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd
Standardized measure of discounted
future net cash flowsg h
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
46,700
21,500
5,000
5,900
14,300
8,700
5,600
–
–
–
–
–
–
–
188,900
123,800
15,600
9,600
39,900
19,000
34,200
30,100
2,400
200
1,500
600
20,900
900
–
–
–
–
–
–
–
269,800
175,400
23,000
15,700
55,700
28,300
27,400
future net cash flows
10,600
4,500
47,400
400
11,100
19,800
20,900
16,600
12,600
143,900
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeari
Subsidiaries
Equity-accounted
entities (BP share)
$ million
Total subsidiaries and
equity-accounted
entities
(30,900)
13,200
6,600
75,100
(21,900)
(18,200)
(11,000)
(6,500)
10,000
16,400
(5,700)
2,500
2,800
15,700
2,000
(1,400)
(2,500)
(2,700)
1,500
12,200
(36,600)
15,700
9,400
90,800
(19,900)
(19,600)
(13,500)
(9,200)
11,500
28,600
a The marker prices used were Brent $110.96/bbl, Henry Hub $4.12/mmBtu.
b Production costs, which include production taxes, and development costs relating to future production of proved reserves are based on the continuation of existing economic conditions. Future
decommissioning costs are included.
c Taxation is computed using appropriate year-end statutory corporate income tax rates.
d Future net cash flows from oil and natural gas production are discounted at 10% regardless of the group assessment of the risk associated with its producing activities.
e Non-controlling interest in BP Trinidad and Tobago LLC amounted to $1,600 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted investments of
those entities.
g Non-controlling interest in TNK-BP amounted to $1,600 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements.
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
BP Annual Report and Form 20-F 2013
221
Operational and statistical information
The following tables present operational and statistical information related to production, drilling, productive wells and acreage. Figures include
amounts attributable to assets held for sale.
Crude oil and natural gas production
The following table shows crude oil and natural gas production for the years ended 31 December 2013, 2012 and 2011.
Production for the yeara
Europe
North
America
South
America
Africa
Asia
Australasia
Total
Subsidiaries
Crude oilb
2013
2012
2011
Natural gasc
2013
2012
2011
Equity-accounted entities(BP share)
Crude oilb
2013
2012
2011
Natural gasc
2013
2012
2011
UK
Rest of
Europe
61
86
113
157
414
355
–
–
–
–
–
–
34
23
32
80
8
13
–
–
–
–
–
–
US
363
390
453
1,539
1,651
1,843
–
–
–
–
–
–
Rest of
North
America
Russia
Rest of
Asia
–
1
2
11
13
14
–
–
–
–
–
–
30
28
39
2,221
2,097
2,197
73
80
90
386
394
392
225
202
190
561
590
558
–
–
–
8
–
–
–
–
–
–
–
–
829
863
865
780
734
699
141
139
138
494
633
618
232
217
210
41
72
34
thousand barrels per day
25
27
25
879
896
992
million cubic feet per day
780
787
795
5,845
6,193
6,393
thousand barrels per day
–
–
–
1,134
1,160
1,165
million cubic feet per day
–
–
–
1,216
1,200
1,125
a Production excludes royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b Crude oil includes natural gas liquids and condensate.
c Natural gas production excludes gas consumed in operations.
Because of rounding, some totals may not exactly agree with the sum of their component parts.
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 at 31 December 2013. 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.
Europe
Rest of
Europe
UK
North
America
Rest of
North
America
US
Number of productive wells at 31 December 2013
Oil wellsa
Gas wellsb
– gross
– net
– gross
– net
115
71
68
29
63
25
6
1
Oil and natural gas acreage at 31 December 2013
Developed
Undevelopedc
– gross
– net
– gross
– net
128
71
1,118
672
39
16
1,196
403
2,456
975
21,445
9,367
6,340
3,334
6,669
4,585
55
28
364
179
223
109
9,710
7,638
South
America
4,681
2,583
688
239
1,634
453
29,100
12,943
Africa
Asia
Australasia
Total
Russia
41,541
7,779
72
14
608
441
135
52
Rest of
Asia
2,166
439
761
280
621
221
26,538
17,142
4,380
831
257,896
50,285
1,982
355
20,141
7,258
13
2
74
14
51,698
12,343
23,613
10,175
Thousands of acres
162
35
16,021
11,254
15,509
5,425
368,389
112,180
a Includes approximately 7,639 gross (1,491 net) multiple completion wells (more than one formation producing into the same well bore).
b Includes approximately 2,859 gross (1,350 net) multiple completion wells. If one of the multiple completions in a well is an oil completion, the well is classified as an oil well.
c Undeveloped acreage includes leases and concessions.
222
BP Annual Report and Form 20-F 2013
Operational and statistical information – continued
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.
2013
Exploratory
Productive
Dry
Development
Productive
Dry
2012
Exploratory
Productive
Dry
Development
Productive
Dry
2011
Exploratory
Productive
Dry
Development
Productive
Dry
Europe
North
America
South
America
Africa
Asia
Australasia
Total
Rest of
Europe
Rest of
North
America
US
Russiae
Rest of
Asia
–
–
12.7
1.1
1.2
0.2
285.7
0.4
0.3
–
17.1
0.6
–
–
–
–
–
–
317.8
–
34.1
2.1
199.4
0.2
–
–
–
–
–
–
–
–
–
–
–
–
4.5
1.4
94.6
2.7
5.8
1.0
78.9
–
1.5
0.6
4.0
–
12.6
0.2
395.0
–
3.5
0.9
58.0
0.7
2.3
0.5
14.7
5.0
–
–
17.7
1.0
552.5
–
43.1
9.5
4.4
0.2
2.1
–
16.7
7.2
101.3
3.0
16.0
2.7
582.0
–
1.0
0.3
45.1
0.4
–
0.5
0.2
0.4
27.2
4.5
848.3
4.6
–
–
–
–
40.2
7.3
1,011.6
10.5
0.2
0.3
–
–
58.9
10.1
945.5
6.3
UK
1.0
–
1.0
–
–
0.2
1.6
–
0.4
–
1.7
–
e Information for 2011 and 2012 includes BP’s share of TNK-BP which was sold to Rosneft on 21 March 2013.
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 31 December 2013. Suspended development wells and long-term suspended exploratory wells are also included in the
table.
At 31 December 2013
Exploratory
Gross
Net
Development
Gross
Net
Europe
North
America
South
America
Africa
Asia
Australasia
Total
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
–
–
32.0
9.2
3.0
1.1
780.0
169.1
3.0
1.5
55.0
27.5
6.0
2.2
33.0
16.6
10.0
5.2
20.0
6.1
–
–
100.0
19.8
4.0
0.8
58.0
20.7
–
–
57.0
19.7
10.0
1.4
1,065.0
266.3
UK
2.0
0.8
6.0
4.0
F
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BP Annual Report and Form 20-F 2013
223
Parent company financial statements of BP p.l.c.
Independent auditor’s report to the members of BP p.l.c.
We have audited the parent company financial statements of BP p.l.c. for the year ended 31 December 2013 which comprise the company balance
sheet, the company cash flow statement, the company statement of total recognized gains and losses and the related notes 1 to 13. The financial
reporting framework that has been applied in their preparation is applicable law and United Kingdom Accounting Standards (United Kingdom Generally
Accepted Accounting Practice).
This report is made solely to the company’s members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work
has been undertaken so that we might state to the company’s members those matters we are required to state to them in an auditor’s report and for
no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the
company’s members as a body, for our audit work, for this report, or for the opinions we have formed.
Respective responsibilities of directors and auditor
As explained more fully in the Statement of directors’ responsibilities set out on page 116, the directors are responsible for the preparation of the
parent company financial statements and for being satisfied that they give a true and fair view. Our responsibility is to audit and express an opinion on
the parent company financial statements in accordance with applicable law and International Standards on Auditing (UK and Ireland). Those standards
require us to comply with the Auditing Practices Board’s Ethical Standards for Auditors.
Scope of the audit of the financial statements
An audit involves obtaining evidence about the amounts and disclosures in the financial statements sufficient to give reasonable assurance that the
financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of: whether the accounting
policies are appropriate to the parent company’s circumstances and have been consistently applied and adequately disclosed; the reasonableness of
significant accounting estimates made by the directors; and the overall presentation of the financial statements. In addition, we read all the financial
and non-financial information in the Annual Report and Accounts to identify material inconsistencies with the audited financial statements and to
identify any information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of
performing the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.
Opinion on financial statements
In our opinion the parent company financial statements:
• give a true and fair view of the state of the company’s affairs as at 31 December 2013;
• have been properly prepared in accordance with United Kingdom Generally Accepted Accounting Practice; and
• have been prepared in accordance with the requirements of the Companies Act 2006.
Opinion on other matters prescribed by the Companies Act 2006
In our opinion:
• the part of the Directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006; and
• the information given in the Strategic report and the Directors’ report for the financial year for which the financial statements are prepared is
consistent with the parent company financial statements.
Matters on which we are required to report by exception
We have nothing to report in respect of the following matters where the Companies Act 2006 requires us to report to you if, in our opinion:
• adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not been received from branches
not visited by us; or
• the parent company financial statements and the part of the Directors’ remuneration report to be audited are not in agreement with the accounting
records and returns; or
• certain disclosures of directors’ remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
Other matter
We have reported separately on the group financial statements of BP p.l.c. for the year ended 31 December 2013. That report includes an emphasis of
matter on the significant uncertainty over provisions and contingencies related to the Gulf of Mexico oil spill.
Ernst & Young LLP
John C. Flaherty (Senior Statutory Auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
6 March 2014
1. The maintenance and integrity of the BP p.l.c. website are the responsibility of the directors; the work carried out by the auditors does not
involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the
financial statements since they were initially presented on the website.
2. Legislation in the United Kindom governing the preparation and dissemination of financial statements may differ from legislation in other
jurisdictions.
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
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BP Annual Report and Form 20-F 2013
Company balance sheet
At 31 December
Fixed assets
Investments
Subsidiary undertakings
Associated undertakings
Total fixed assets
Current assets
Debtors – amounts falling due within one year
Deferred taxation
Cash at bank and in hand
Creditors – amounts falling due within one year
Net current assets
Total assets less current liabilities
Creditors – amounts falling due after more than one year
Net assets excluding pension plan surplus (deficit)
Defined benefit pension plan surplus (deficit)
Net assets
Represented by
Capital and reserves
Called-up share capital
Share premium account
Capital redemption reserve
Merger reserve
Own shares
Treasury shares
Share-based payment reserve
Profit and loss account
Note
2013
3
3
4
2
5
5
6
7
8
8
8
8
8
8
8
134,125
2
134,127
21,550
41
6
21,597
4,267
17,330
151,457
4,642
146,815
979
147,794
5,129
10,061
1,260
26,509
(601)
(20,370)
1,661
124,145
$ million
2012
133,420
2
133,422
17,496
–
9
17,505
2,604
14,901
148,323
4,487
143,836
(1,913)
141,923
5,261
9,974
1,072
26,509
(280)
(20,774)
1,604
118,557
147,794
141,923
The financial statements on pages 225-234 were approved and signed by the group chief executive on 6 March 2014 having been duly authorized to do
so by the board of directors:
R W Dudley Group Chief Executive
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BP Annual Report and Form 20-F 2013
225
Company cash flow statement
For the year ended 31 December
Net cash outflow from operating activities
Servicing of finance and returns on investments
Interest received
Interest paid
Dividends received
Net cash inflow from servicing of finance and returns on investments
Tax paid
Capital expenditure and financial investment
Payments for fixed assets – investments
Net cash outflow for capital expenditure and financial investment
Equity dividends paid
Net cash inflow before financing
Financing
Other share-based payment movements
Repurchases of ordinary share capital
Net cash outflow from financing
(Decrease) increase in cash
Company statement of total recognized gains and losses
For the year ended 31 December
Profit for the year
Currency translation differences
Actuarial gain (loss) relating to pensions
Tax on actuarial gain (loss) relating to pensions
Total recognized gains and losses relating to the year
2013
$ million
2012
(4,813)
(1,272)
Note
9
116
(43)
16,228
183
(43)
13,515
16,301
13,655
(2)
(2)
(690)
(690)
(7,060)
(7,060)
(5,441)
(5,294)
5,355
27
135
(5,493)
(5,358)
9
(3)
(18)
–
(18)
9
Note
2013
15,691
47
2,108
(41)
6
2
$ million
2012
12,322
(98)
(573)
–
17,805
11,651
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
226
BP Annual Report and Form 20-F 2013
Notes on the financial statements
1. Accounting policies
Accounting standards
These accounts are prepared on a going concern basis and in accordance with the Companies Act 2006 and applicable UK accounting standards.
Accounting convention
The financial statements are prepared under the historical cost convention.
Foreign currency transactions
Functional currency is the currency of the primary economic environment in which an entity operates and is normally the currency in which the entity
primarily generates and expends cash. Transactions in foreign currencies are initially recorded in the functional currency by applying the rate of
exchange ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated into the functional
currency at the rate of exchange ruling at the balance sheet date. Any resulting exchange differences are included in profit for the year. Exchange
adjustments arising when the opening net assets and the profits for the year retained by non-US dollar functional currency branches are translated into
US dollars are taken to a separate component of equity and reported in the statement of total recognized gains and losses.
Investments
Investments in subsidiaries and associated undertakings are recorded at cost. The company assesses investments for impairment whenever events or
changes in circumstances indicate that the carrying value of an investment may not be recoverable. If any such indication of impairment exists, the
company makes an estimate of its recoverable amount. Where the carrying amount of an investment exceeds its recoverable amount, the investment
is considered impaired and is written down to its recoverable amount.
Share-based payments
Equity-settled transactions
The cost of equity-settled transactions with employees of the company and other members of the group is measured by reference to the fair value at
the date at which equity instruments are granted and is recognized as an expense over the vesting period, which ends on the date on which the
employees become fully entitled to the award. Fair value is determined by using an appropriate valuation model. In valuing equity-settled transactions,
no account is taken of any vesting conditions, other than conditions linked to the price of the shares of the company (market conditions). Non-vesting
conditions, such as the condition that employees contribute to a savings-related plan, are taken into account in the grant-date fair value, and failure to
meet a non-vesting condition, where this is within the control of the employee, is treated as a cancellation.
Cash-settled transactions
The cost of cash-settled transactions is measured at fair value and recognized as an expense over the vesting period, with a corresponding liability for
the cumulative expense recognized on the balance sheet.
Pensions
The cost of providing benefits under the defined benefit plans is determined separately for each plan using the projected unit credit method, which
attributes entitlement to benefits to the current period (to determine current service cost) and to the current and prior periods (to determine the present
value of the defined benefit obligation). Past service costs and settlement costs are recognized immediately when the company becomes committed
to a change in pension plan design, or when a curtailment or settlement event occurs.
The interest element of the defined benefit cost represents the change in present value of scheme obligations resulting from the passage of time, and
is determined by applying the discount rate to the opening present value of the benefit obligation, taking into account material changes in the obligation
during the year. The expected return on plan assets is based on an assessment made at the beginning of the year of long-term market returns on plan
assets, adjusted for the effect on the fair value of plan assets of contributions received and benefits paid during the year. The difference between the
expected return on plan assets and the interest cost is recognized in the income statement as other finance income or expense.
Actuarial gains and losses are recognized in full within the statement of total recognized gains and losses in the period in which they occur.
The defined benefit pension plan surplus or deficit in the balance sheet comprises the total for each plan of the present value of the defined benefit
obligation (using a discount rate based on high quality corporate bonds), less the fair value of plan assets out of which the obligations are to be settled
directly. Fair value is based on market price information and, in the case of quoted securities, is the published bid price. The surplus or deficit, net of
taxation thereon, is presented separately above the total for net assets on the face of the balance sheet.
The BP Pension Fund is operated in a way that does not allow the individual participating employing companies in the pension fund to identify their
share of the underlying assets and liabilities of the fund, and hence the company recognizes the full defined benefit pension plan surplus or deficit in its
balance sheet.
Deferred taxation
Deferred tax is recognized in respect of all timing differences that have originated but not reversed at the balance sheet date where transactions or
events have occurred at that date that will result in an obligation to pay more, or a right to pay less, tax in the future.
Deferred tax assets are recognized only to the extent that it is considered more likely than not that there will be suitable taxable profits from which the
underlying timing differences can be deducted.
Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which timing differences reverse, based
on tax rates and laws enacted or substantively enacted at the balance sheet date.
Use of estimates
The preparation of accounts in conformity with 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.
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BP Annual Report and Form 20-F 2013
227
2. Taxation
Tax charge included in the statement of total recognized gains and losses
Deferred tax
Origination and reversal of timing differences in the current year
This comprises:
Actuarial gain relating to pensions and other post-retirement benefits
Other taxable timing differences
Deferred tax
Deferred tax liability
Pensions
Deferred tax asset
Other taxable timing differences
Net deferred tax liability (asset)
Analysis of movements during the year
At 1 January
Credit for the year on ordinary activities
Charge for the year in the statement of total recognized gains and losses
At 31 December
$ million
2013
2012
–
41
(41)
41
41
–
–
(41)
41
–
–
–
–
–
–
–
–
–
–
–
At 31 December 2013, deferred tax assets of $72 million on other timing differences (2012 $82 million on other timing differences and $97 million on
pensions) were not recognized as it is not considered more likely than not that suitable taxable profits will be available in the company from which the
future reversal of the underlying timing differences can be deducted. It is anticipated that the reversal of these timing differences will benefit other
group companies in the future.
3. Fixed assets – investments
Cost
At 1 January 2013
Additions
At 31 December 2013
Amounts provided
At 1 January 2013
At 31 December 2013
Cost
At 1 January 2012
Additions
At 31 December 2012
Amounts provided
At 1 January 2012
At 31 December 2012
Net book amount
At 31 December 2013
At 31 December 2012
Subsidiary
undertakings
Associated
undertakings
Shares
Shares
Loans
Total
$ million
133,494
705
134,199
74
74
126,434
7,060
133,494
74
74
134,125
133,420
2
–
2
–
–
2
–
2
–
–
2
2
2
–
2
2
2
2
–
2
2
2
–
–
133,498
705
134,203
76
76
126,438
7,060
133,498
76
76
134,127
133,422
The more important subsidiary undertakings of the company at 31 December 2013 and the percentage holding of ordinary share capital (to the nearest
whole number) are set out below. A complete list of investments in subsidiary undertakings, joint ventures and associated undertakings will be
attached to the company’s annual return made to the Registrar of Companies.
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
228
BP Annual Report and Form 20-F 2013
3. Fixed assets – investments – continued
Subsidiary undertakings
International
BP Corporate Holdings
BP Global Investments
BP International
BP Shipping
Burmah Castrol
South Africa
BP Southern Africa
US
%
100
100
100
100
100
Country of
incorporation
England & Wales
England & Wales
England & Wales
England & Wales
Scotland
Principal activities
Investment holding
Investment holding
Integrated oil operations
Shipping
Lubricants
75
South Africa
Refining and marketing
BP Holdings North America
100
England & Wales
Investment holding
The carrying value of BP International in the accounts of the company at 31 December 2013 was $62.63 billion (2012 $62.63 billion).
4. Debtors
Group undertakings
The carrying amounts of debtors approximate their fair value.
5. Creditors
Group undertakings
Accruals and deferred income
Other creditors
2013
Within
1 year
21,550
21,550
Within
1 year
2,526
1,540
201
4,267
2013
After
1 year
4,584
58
–
4,642
Within
1 year
2,376
27
201
2,604
$ million
2012
Within
1 year
17,496
17,496
$ million
2012
After
1year
4,274
38
175
4,487
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The carrying amounts of creditors approximate their fair value.
Amounts falling due after one year include $4,236 million payable to a group undertaking. This amount is subject to interest payable quarterly at LIBOR
plus 55 basis points.
Other creditors includes an amount of $175 million payable in respect of the settlement with the US Securities and Exchange Commission described in
Note 2 of the consolidated financial statements.
The maturity profile of the financial liabilities included in the balance sheet at 31 December is shown in the table below. These amounts are included
within Creditors – amounts falling due after more than one year, and are denominated in US dollars.
Due within
1 to 2 years
2 to 5 years
More than 5 years
2013
372
22
4,248
4,642
$ million
2012
230
17
4,240
4,487
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2013
229
6. Pensions
The primary pension arrangement in the UK is a funded final salary pension plan under which retired employees draw the majority of their benefit as an
annuity. The UK plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners in the UK are eligible for
membership of a defined contribution plan.
The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most recent
actuarial review was 31 December 2013. The principal plans are subject to a formal actuarial valuation every three years in the UK. The most recent
formal actuarial valuation of the main UK pension plan was as at 31 December 2011.
The material financial assumptions used for estimating the benefit obligations of the plans are set out below. The assumptions are reviewed by
management at the end of each year, and are used to evaluate accrued pension and other post-retirement benefits at 31 December and pension
expense for the following year.
Financial assumptions used to determine benefit obligation
Expected long-term rate of return
Discount rate for pension plan liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inflation for pension plan liabilities
Financial assumptions used to determine benefit expense
Discount rate for pension plan service costs
Discount rate for pension plan other finance expense
Inflation for pension plan service costs
2013
2012
2011
%
6.9
4.6
5.1
3.3
3.3
3.3
6.9
4.4
4.9
3.1
3.1
3.1
7.0
4.8
5.1
3.2
3.2
3.2
%
2013
2012
2011
4.4
4.4
3.1
4.8
4.8
3.2
5.5
5.5
3.5
Our discount rate assumption is based on third-party AA corporate bond indices and we use yields that reflect the maturity profile of the expected
benefit payments. The inflation rate assumption is based on the difference between the yields on index-linked and fixed-interest long-term government
bonds. The inflation assumptions are used to determine the rate of increase for pensions in payment and the rate of increase in deferred pensions.
Our assumption for the rate of increase in salaries is based on our inflation assumption plus an allowance for expected long-term real salary growth.
This includes allowance for promotion-related salary growth of 0.7%.
In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. The mortality assumptions reflect best
practice in the UK, and have been chosen with regard to the latest available published tables adjusted where appropriate to reflect the experience of
the group and an extrapolation of past longevity improvements into the future.
Mortality assumptions
Life expectancy at age 60 for a male currently aged 60
Life expectancy at age 60 for a male currently aged 40
Life expectancy at age 60 for a female currently aged 60
Life expectancy at age 60 for a female currently aged 40
The fair values of the various categories of asset held by the pension plan at 31 December are set out below.
2013
27.8
30.7
29.5
32.2
2012
27.7
30.6
29.4
32.1
2011
27.6
30.5
29.3
32.0
Listed equity – developed
– emerging
Private equity
Government issued nominal bondsa
Index-linked bondsa
Corporate bondsa
Propertyb
Cash
Other
Present value of plan liabilities
Surplus (deficit) in the plan
a Bonds held are typically denominated in sterling.
b Property held is all located in the United Kingdom.
Expected
long-term
rate of
return
%
8.0
8.0
8.0
3.8
3.6
4.6
6.5
0.8
0.8
6.9
2013
2012
Expected
long-term
rate of
return
%
8.0
8.0
8.0
2.8
2.6
4.2
6.5
0.9
0.9
6.9
Expected
long-term
rate of
return
%
8.0
8.0
8.0
3.0
2.8
4.9
6.5
1.7
1.7
7.0
Market
value
$ million
15,659
1,074
2,879
544
491
3,850
1,783
1,000
66
27,346
29,259
(1,913)
Market
value
$ million
17,341
2,290
2,907
549
787
4,427
2,200
855
160
31,516
30,496
1,020
$ million
2011
Market
value
$ million
13,622
890
2,690
513
390
3,238
1,710
470
64
23,587
25,675
(2,088)
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
230
BP Annual Report and Form 20-F 2013
6. Pensions – continued
Analysis of the amount charged to operating profit
Current service costa
Settlement, curtailment and special termination benefits
Payments to defined contribution plans
Total operating chargec
Analysis of the amount credited (charged) to other finance income
Expected return on pension plan assets
Interest on pension plan liabilities
Other finance income
Analysis of the amount recognized in the statement of total recognized gains and losses
Actual return less expected return on pension plan assets
Change in assumptions underlying the present value of the plan liabilities
Experience gains and losses arising on the plan liabilities
Actuarial gain (loss) recognized in statement of total recognized gains and losses
Movements in benefit obligation during the year
Benefit obligation at 1 January
Exchange adjustment
Current service costa
Interest cost
Curtailments
Disposals
Special termination benefitsb
Contributions by plan participantse
Benefit payments (funded plans)c
Benefit payments (unfunded plans)c
Actuarial (gain) loss on obligation
Benefit obligation at 31 December
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustment
Expected return on plan assetsa d
Contributions by plan participantse
Contributions by employers (funded plans)
Disposals
Benefit payments (funded plans)c
Actuarial gain on plan assetsd
Fair value of plan assets at 31 Decemberf
Surplus (deficit) at 31 December
2013
497
(22)
24
499
1,803
(1,221)
582
2,007
60
41
2,108
2013
29,259
705
497
1,221
(24)
(9)
2
37
(1,087)
(4)
(101)
30,496
27,346
822
1,803
37
597
(9)
(1,087)
2,007
31,516
1,020
$ million
2012
477
(1)
14
490
1,680
(1,249)
431
989
(1,446)
(116)
(573)
$ million
2012
25,675
1,313
477
1,249
(8)
(10)
7
39
(1,038)
(7)
1,562
29,259
23,587
1,215
1,680
39
884
(10)
(1,038)
989
27,346
(1,913)
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a The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are included in current service cost.
b The charge for special termination benefits represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
c The benefit payments amount shown above comprises $1,073 million benefits plus $18 million of plan expenses incurred in the administration of the benefit.
d The actual return on plan assets is made up of the sum of the expected return on plan assets and the actuarial gain on plan assets as disclosed above.
e The contributions by plan participants are mostly comprised of contributions made under salary sacrifice arrangements.
f Reflects $31,362 million of assets held in the BP Pension Fund (2012 $27,219 million) and $114 million held in the BP Global Pension Trust (2012 $94 million), with $40 million representing the
company’s share of Merchant Navy Officers Pension Fund (2012 $32 million).
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2013
231
6. Pensions – continued
Reconciliation of plan surplus (deficit) to balance sheet
Surplus (deficit) at 31 December
Deferred tax
Represented by
Asset recognized on balance sheet
Liability recognized on balance sheet
The aggregate level of employer contributions into the BP Pension Fund in 2014 is expected to be $485 million.
$ million
2012
2013
1,020
(41)
979
1,238
(259)
979
(1,913)
–
(1,913)
–
(1,913)
(1,913)
History of surplus (deficit) and of experience gains and losses
Benefit obligation at 31 December
Fair value of plan assets at 31 December
Surplus (deficit)
Experience gains and losses on plan liabilities
Amount ($ million)
Percentage of benefit obligation
Actual return less expected return on pension plan assets
Amount ($ million)
Percentage of plan assets
Actuarial gain (loss) recognized in statement of total recognized gains and losses
Amount ($ million)
Percentage of benefit obligation
Cumulative amount recognized in statement of total recognized gains and losses
7. Called-up share capital
The allotted, called-up and fully paid share capital at 31 December was as follows:
Issued
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares for employee share-based payment plansb
Repurchase of ordinary share capitalc
31 December
2013
2012
2011
2010
30,496
31,516
1,020
29,259
27,346
25,675
23,587
(1,913)
(2,088)
20,742
22,612
1,870
$ million
2009
19,882
20,953
1,071
41
0%
2,007
6%
(116)
0%
989
4%
2,108
7%
(4,470)
(573)
2%
(6,578)
(84)
0%
12
0%
(146)
(1%)
(1,976)
(8%)
(4,770)
(19%)
(6,005)
1,479
7%
1,634
8%
457
2%
(1,235)
(585)
(3%)
(1,692)
Shares
(thousand)
7,233
5,473
20,959,159
202,124
18,203
(752,854)
20,426,632
2013
$ million
12
9
21
5,240
51
5
(188)
5,108
5,129
Shares
(thousand)
7,233
5,473
20,813,410
138,406
7,343
–
20,959,159
2012
$ million
12
9
21
5,203
35
2
–
5,240
5,261
a The nominal amount of 8% cumulative first preference shares and 9% cumulative second preference shares that can be in issue at any time shall not exceed £10,000,000 for each class of preference
shares.
b Consideration received relating to the issue of new shares for employee share plans amounted to $116 million (2012 $47 million).
c Purchased for a total consideration of $5,493 million, including transaction costs of $30 million. All shares purchased were for cancellation. The repurchased shares represented 3.6% of ordinary share
capital.
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 £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.
During 2013 the company repurchased 753 million ordinary shares at a cost of $5,463 million as part of the share repurchase programme announced
on 22 March 2013. The number of shares in issue is reduced when shares are repurchased, but is not reduced in respect of the year-end commitment
to repurchase shares subsequent to the end of the year, for which an amount of $1,430 million has been accrued at 31 December 2013 (2012 nil).
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
232
BP Annual Report and Form 20-F 2013
8. Capital and reserves
At 1 January 2013
Currency translation differences
Actuarial gain on pensions (net of tax)
Share-based payments
Repurchases of ordinary share capital
Profit for the year
Dividends
At 31 December 2013
At 1 January 2012
Currency translation differences
Actuarial loss on pensions (net of tax)
Share-based payments
Profit for the year
Dividends
At 31 December 2012
Share
capital
5,261
–
–
5
(188)
–
51
5,129
Share
capital
5,224
–
–
2
–
35
5,261
Share
premium
account
Capital
redemption
reserve
9,974
–
–
138
–
–
(51)
10,061
1,072
–
–
–
188
–
–
1,260
Share
premium
account
Capital
redemption
reserve
9,952
–
–
57
–
(35)
9,974
1,072
–
–
–
–
–
1,072
Merger
reserve
26,509
–
–
–
–
–
–
26,509
Merger
reserve
26,509
–
–
–
–
–
26,509
Own
shares
(280)
–
–
(321)
–
–
–
(601)
Own
shares
(388)
–
–
108
–
–
(280)
Treasury
shares
(20,774)
–
–
404
–
–
–
(20,370)
Treasury
shares
(20,935)
–
–
161
–
–
(20,774)
Share-based
payment
reserve
1,604
–
–
57
–
–
–
1,661
Share-based
payment
reserve
1,574
–
–
30
–
–
1,604
Profit
and loss
account
118,557
47
2,067
147
(6,923)
15,691
(5,441)
124,145
Profit
and loss
account
112,285
(98)
(573)
(85)
12,322
(5,294)
118,557
$ million
Total
141,923
47
2,067
430
(6,923)
15,691
(5,441)
147,794
$ million
Total
135,293
(98)
(573)
273
12,322
(5,294)
141,923
As a consolidated income statement is presented for the group, a separate income statement for the parent company is not required to be
published.
The profit and loss account reserve includes $24,107 million (2012 $24,107 million), the distribution of which is limited by statutory or other
restrictions.
The accounts for the year ended 31 December 2013 do not reflect the dividend announced on 4 February 2014 and payable in March 2014; this will
be treated as an appropriation of profit in the year ended 31 December 2014.
9. Cash flow
Notes on cash flow statement
Reconciliation of net cash flow to movement of funds
(Decrease) increase in cash
Movement of funds
Net cash at 1 January
Net cash at 31 December
Notes on cash flow statement
(a) Reconciliation of operating profit to net cash outflow from operating activities
Operating profit
Net operating charge for pensions and other post-retirement benefits, less contributions
Dividends, interest and other income
Share-based payments
(Increase) decrease in debtors
Increase in creditors
Net cash outflow from operating activities
(b) Analysis of movements of funds
Cash at bank
2013
$ million
2012
(3)
(3)
9
6
9
9
–
9
2013
2012
15,112
(127)
(16,414)
297
(4,054)
373
(4,813)
11,936
(414)
(13,758)
350
240
374
(1,272)
At
1 January
2013
9
$ million
At
31 December
2013
6
Cash
flow
(3)
F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2013
233
10. Contingent liabilities
The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2013 were $47,042 million (2012 $45,400
million), the majority of which relate to finance debt of subsidiaries. The company has also issued uncapped indemnities and guarantees, including a
guarantee of subsidiaries’ liabilities under the PSC agreement relating to the Gulf of Mexico oil spill (see Note 2 to the consolidated financial
statements), and in relation to potential losses arising from environmental incidents involving ships leased and operated by a subsidiary.
11. Share-based payments
Effect of share-based payment transactions on the company’s result and financial position
Total expense recognized for equity-settled share-based payment transactions
Total expense recognized for cash-settled share-based payment transactions
Total expense recognized for share-based payment transactions
Closing balance of liability for cash-settled share-based payment transactions
Total intrinsic value for vested cash-settled share-based payments
Additional information on the company’s share-based payment plans is provided in Note 13 to the consolidated financial statements.
12. Auditor’s remuneration
Note 37 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a group basis.
13. Directors’ remuneration
Remuneration of directors
Total for all directors
Emoluments
Gains made on the exercise of share options
Amounts awarded under incentive schemes
$ million
2012
669
5
674
12
–
2013
709
10
719
17
2
$ million
2012
12
–
3
2013
16
–
2
Emoluments
These amounts comprise fees and benefits paid to the non-executive chairman and the non-executive directors and, for executive directors, salary
and benefits earned during the relevant financial year, plus cash bonuses awarded for the year. There was no compensation for loss of office in 2013
(2012 nil).
Pension contributions
During 2013, two executive directors participated in a non-contributory pension scheme established for UK employees. Two US executive directors
participated in the US BP Retirement Accumulation Plan during 2013.
Office facilities for former chairmen and deputy chairmen
It is customary for the company to make available to former chairmen and deputy chairmen, who were previously employed executives, the use of
office and basic secretarial facilities following their retirement. The cost involved in doing so is not significant.
Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 81.
The parent company financial statements of BP p.l.c. on pages 224-234 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
234
BP Annual Report and Form 20-F 2013
Additional
disclosures
236 Selected financial information
239 Upstream analysis by region
242 Downstream analysis by region
245 Oil and gas disclosures for the group
252 Environmental expenditure
252 Contractual obligations
253 Regulation of the group’s business
257 Legal proceedings
267 Further note on certain activities
268 Material contracts
268 Property, plant and equipment
268 Related-party transactions
269 Exhibits
269 Certain definitions
271 Directors’ report information
271 Cautionary statement
A
d
d
i
t
i
o
n
a
l
d
i
s
c
l
o
s
u
r
e
s
BP Annual Report and Form 20-F 2013
235
Selected financial information
This information, insofar as it relates to 2013, has been extracted or derived from the audited consolidated financial statements of the BP group
presented on page 115. Note 1 to the financial statements includes details on the basis of preparation of these financial statements. The selected
information should be read in conjunction with the audited financial statements and related notes elsewhere herein. Comparative financial information
for 2009-12 has been restated to reflect the adoption of amendments to IAS 19 ‘Employee Benefits’. Financial information for 2011 and 2012 has also
been restated to reflect the adoption of IFRS 11 ‘Joint Arrangements’. For further information see Financial statements – Note 1.
Income statement data
Sales and other operating revenues
Underlying replacement cost profit before interest and taxationa
Net favourable (unfavourable) impact of non-operating items and fair value
accounting effectsa
Replacement cost profit (loss) before interest and taxationa
Inventory holding gains (losses)b
Profit (loss) before interest and taxation
Finance costs and net finance expense relating to pensions and other
post-retirement benefits
Taxation
Profit (loss) for the year
Profit (loss) for the year attributable to BP shareholders
Inventory holding (gains) lossesb, net of taxation
Replacement cost profit (loss) for the year attributable to BP shareholdersa
Non-operating items and fair value accounting effectsa, net of taxation
Underlying replacement cost profit for the year attributable to BP shareholdersa
Per ordinary share – cents
Profit (loss) for the year attributable to BP shareholders
Basic
Diluted
Replacement cost profit (loss) for the year attributable to BP shareholders
Underlying replacement cost profit for the year attributable to BP shareholders
Dividends paid per share – cents
– pence
Capital expenditure and acquisitionsc
Acquisitions and asset exchanges
Organic capital expenditured
Balance sheet data (at 31 December)
Total assets
Net assets
Share capital
BP shareholders’ equity
Finance debt due after more than one year
Net debt to net debt plus equitye
Ordinary share dataf
Basic weighted average number of shares
Diluted weighted average number of shares
2013
2012
2011
2010
2009
$ million except per share amounts
379,136
375,765
375,713
297,107
239,272
22,776
26,454
33,601
31,704
22,673
9,283
32,059
(290)
31,769
(1,548)
(6,463)
23,758
23,451
230
23,681
(10,253)
13,428
123.87
123.12
125.08
70.92
36.50
23.399
36,612
71
24,600
(6,091)
20,363
(594)
19,769
(1,638)
(6,880)
11,251
11,017
411
11,428
5,643
17,071
57.89
57.50
60.05
89.70
33.00
20.852
25,204
200
23,950
3,580
37,181
2,634
39,815
(1,587)
(12,619)
25,609
25,212
(1,800)
23,412
(2,242)
21,170
133.35
131.74
123.83
111.97
28.00
17.404
31,959
11,283
19,580
(37,190)
(169)
(5,486)
1,784
(3,702)
(1,605)
1,638
(3,669)
(4,064)
(1,195)
(5,259)
25,436
20,177
(21.64)
(21.64)
(28.01)
107.39
14.00
8.679
23,016
3,406
18,218
22,504
3,922
26,426
(1,609)
(8,273)
16,544
16,363
(2,623)
13,740
622
14,362
87.34
86.40
73.34
76.66
56.00
36.417
20,309
308
20,001
305,690
130,407
5,129
129,302
40,811
16.2%
300,466
119,752
5,261
118,546
38,767
18.7%
292,907
112,585
5,224
111,568
35,169
20.4%
272,262
95,891
5,183
94,987
30,710
21.2%
235,968
102,113
5,179
101,613
25,518
20.4%
Shares million
18,931
19,046
19,028
19,158
18,905
19,136
18,786
18,998
18,732
18,936
a RC profit or loss for the group, underlying RC profit or loss and fair value accounting effects are not recognized GAAP measures. For further information, see pages 237 and 238 and Certain definitions
on page 269.
b See Certain definitions and also see Financial statements – Note 7 for an analysis of inventory holding gains and losses by segment.
c Includes asset exchanges. All capital expenditure and acquisitions during the past five years have been financed from cash flow from operations, disposal proceeds and external financing.
d Organic capital expenditure excludes acquisitions and asset exchanges, and: in 2013 $11,941 million relating to our investment in Rosneft; in 2012 $1,054 million associated with deepening our
US natural gas and North Sea asset bases; in 2011 $1,096 million associated with deepening our US natural gas bases; in 2010 $900 million relating to the formation of a partnership with Value Creation
Inc. to develop the Terre de Grace oil sands acreage and $492 million for the purchase of additional interests in the Valhall and Hod fields in the North Sea.
e Net debt and the ratio of net debt to net debt plus equity are not recognized GAAP measures. We believe these numbers are useful information to investors. Further information on net debt is given in
Financial statements – Note 28.
f The number of ordinary shares shown has been used to calculate the per share amounts.
236
BP Annual Report and Form 20-F 2013
Non-operating items
Non-operating items are charges and credits arising in consolidated entities and in TNK-BP and Rosneft that are included in the financial statements
and that BP discloses separately because it considers such disclosures to be meaningful and relevant to investors. They are items that management
considers not to be part of underlying business operations and are disclosed in order to enable investors to understand better and evaluate the group’s
reported financial performance. An analysis of non-operating items is shown in the table below.
Upstream
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Othera
Downstream
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other
TNK-BP
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Otherb
Rosneft
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Other
Other businesses and corporate
Impairment and gain (loss) on sale of businesses and fixed assets
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivativesc
Otherd
Gulf of Mexico oil spill response
Total before interest and taxation
Finance costse
Taxation credit (charge)f
Total after taxation
2013
2012
(802)
(20)
–
459
(1,001)
(1,364)
(348)
(134)
(15)
–
(38)
(535)
12,500
–
–
–
–
12,500
(35)
(10)
–
–
–
(45)
(196)
(241)
(3)
–
19
(421)
(430)
3,638
(48)
–
347
(748)
3,189
(2,934)
(171)
(32)
–
(35)
(3,172)
(55)
(83)
–
–
384
246
–
–
–
–
–
–
(282)
(261)
(15)
–
(240)
(798)
$ million
2011
2,131
(27)
–
191
(1,165)
1,130
(332)
(221)
(4)
–
(45)
(602)
–
–
–
–
–
–
–
–
–
–
–
–
275
(220)
(39)
(123)
(715)
(822)
(4,995)
3,800
9,705
(39)
867
10,533
(5,530)
(19)
251
(5,298)
3,506
(58)
(1,253)
2,195
A
d
d
i
t
i
o
n
a
l
d
i
s
c
l
o
s
u
r
e
s
a 2013 included $845 million relating to the value ascribed to block BM-CAL-13 offshore Brazil, following the acquisition of upstream assets from Devon Energy in 2011, which was written off as a result
of the Pitanga exploration well not encountering commercial quantities of oil or gas. 2012 included a charge of $370 million relating to onerous gas marketing and trading contracts and $308 million
relating to exploration expense associated with our US natural gas assets (2011 $395 million). 2011 included a charge of $700 million associated with the termination of the agreement to sell our 60%
interest in Pan American Energy LLC to Bridas Corporation.
b 2012 included dividend income from TNK-BP of $709 million and a charge of $325 million to settle disputes with AAR.
c Relates to an embedded derivative arising from a financing arrangement.
d 2012 included charges of $244 million relating to our exit from the solar business (2011 $717 million).
e Finance costs relate to the Gulf of Mexico oil spill. See Financial statements – Note 2 for further details.
f For the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair value gains and losses on embedded derivatives, tax is based on statutory rates, except for non-deductible items.
For other items reported for consolidated subsidiaries, tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the items noted above, equity-accounted earnings and certain
deferred tax adjustments relating to changes in UK taxation). Non-operating items reported within the equity-accounted earnings of TNK-BP and Rosneft are reported net of tax.
BP Annual Report and Form 20-F 2013
237
Non-GAAP information on fair value accounting effects
The impacts of fair value accounting effects, relative to management’s internal measure of performance, and a reconciliation to GAAP information is
also set out below. Further information on fair value accounting effects is provided on page 269.
Upstream
Unrecognized gains (losses) brought forward from previous period
Unrecognized (gains) losses carried forward
Favourable (unfavourable) impact relative to management’s measure of performance
Downstreama
Unrecognized gains (losses) brought forward from previous period
Unrecognized (gains) losses carried forward
Favourable (unfavourable) impact relative to management’s measure of performance
Taxation credit (charge)b
By region
Upstream
US
Non-US
Downstreama
US
Non-US
2013
2012
$ million
2011
(404)
160
(244)
501
(679)
(178)
(422)
142
(280)
(269)
25
(244)
(211)
33
(178)
(538)
404
(134)
74
(501)
(427)
(561)
216
(345)
(67)
(67)
(134)
(441)
14
(427)
(527)
538
11
137
(74)
63
74
(27)
47
15
(4)
11
–
63
63
a Fair value accounting effects arise solely in the fuels business.
b Tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for the Gulf of Mexico oil spill, equity-accounted earnings, certain impairment losses, disposal gains and fair value gains
and losses on embedded derivatives and certain deferred tax adjustments relating to changes in UK taxation).
Reconciliation of non-GAAP information
Upstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Replacement cost profit before interest and tax
Downstream
Replacement cost profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Replacement cost profit before interest and tax
Total group
Profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Profit before interest and tax
2013
2012
$ million
2011
16,901
(244)
22,625
(134)
16,657
22,491
26,347
11
26,358
3,097
(178)
2,919
3,291
(427)
2,864
5,407
63
5,470
32,191
(422)
20,330
(561)
31,769
19,769
39,741
74
39,815
238
BP Annual Report and Form 20-F 2013
Upstream analysis by region
The following discussion reviews operations in our upstream business by
geographical area, and lists associated significant events for 2013. BP’s
percentage working interest in oil and gas assets is shown in
parentheses. Working interest is the cost-bearing ownership share of an
oil or gas lease. Consequently, the percentages disclosed for certain
agreements do not necessarily reflect the percentage interests in
reserves and production.
In addition to exploration, development and production activities, our
upstream business also includes midstream and LNG activities.
Midstream activities involve the ownership and management of crude oil
and natural gas pipelines, processing facilities and export terminals, LNG
processing facilities and transportation, and our natural gas liquids (NGLs)
extraction business.
Our LNG supply activities are located in Abu Dhabi, Angola, Australia,
Indonesia and Trinidad. We market around 25% of our LNG production
using BP LNG shipping and contractual rights to access import terminal
capacity in the liquid markets of the US (via Cove Point), the UK (via the
Isle of Grain), Spain (in Bilbao) and Italy (in Rovigo), with the remainder
marketed directly to customers. LNG is supplied to customers in multiple
markets including Japan, South Korea, China, the Dominican Republic,
Argentina, Brazil and Mexico.
Europe
In Europe, BP is active in the UK North Sea and the Norwegian Sea. Our
activities in the North Sea include a focus on maximizing recovery from
existing producing fields and selected new field developments.
• In January production from the new facilities at the Valhall field in the
southern part of the Norwegian North Sea commenced and has now
ramped up to 70 mboe/d. Production from Skarv, which started up in
December 2012, has now ramped up to 160 mboe/d.
• In March BP and its partners, ConocoPhillips, Chevron and Shell,
announced the decision to proceed with a two-year appraisal
programme to evaluate a potential third phase of the Clair field, west of
the Shetland Islands. By the end of 2013, two appraisal wells had been
completed and we are currently drilling a third.
• In April we completed the sale of our interest in the Sean (BP 50%)
field in the North Sea to SSE plc for $288 million.
• In June we completed the sales of our interests in the Harding (BP
70%), Maclure (BP 37.04%), Braes (BP 27.7%), Braemar (BP 52%) and
Devenick (BP 88.7%) fields in the North Sea to TAQA Bratani Ltd for
$1,058 million plus future payments which, depending on oil price and
production, are currently expected to exceed $180 million after tax.
• In June BP announced that it had been awarded two licences in the
Barents Sea as part of Norway’s 22nd offshore licensing round.
• In August the Clair Ridge platform jackets (the steel support structure)
were installed, a major milestone in the project.
• In September BP announced that more than $1.5 billion in contracts
had been awarded to UK-based companies to provide services and
equipment for the major redevelopment of the Schiehallion and Loyal
oil fields to the west of Shetland. The project to redevelop the fields,
which are operated by BP on behalf of its partners, involves two main
elements: a new floating production, storage and offloading vessel
(FPSO) and a major upgrade of the subsea infrastructure that will lie on
the seabed.
• In October the UK government announced a temporary management
scheme to allow the restart of production from the Rhum gas field in
the central North Sea, which has been suspended since November
2010 following the imposition of EU sanctions on Iran. The field is
owned by BP (50%) and the Iranian Oil Company (IOC) under a joint
operating agreement dating back to the early 1970s. BP intends to
recommence operations at Rhum in the future in accordance with the
temporary management scheme, under which the UK government will
assume control of the IOC’s share of Rhum for a period of up to five
years. Revenue from the IOC’s share will be placed in a blocked
account. See Further note on certain activities on page 267 for further
information.
• In December BP was awarded 14 licences in the 27th UK Offshore Oil
and Gas Licensing Round, subject to final government approval.
In the UK sector of the North Sea, BP operates the Forties Pipeline
System (FPS) (BP 100%), an integrated oil and NGLs transportation and
processing system that handles production from more than 80 fields in
the central North Sea. The system has a capacity of more than
675mboe/d, with average throughput in 2013 of 421mboe/d. BP also
operates and has a 36% 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
293mboe/d to a natural gas terminal at Teesside in north-east England.
Average throughput in 2013 was 52mboe/d. CATS offers natural gas
transportation and processing services. In addition, BP operates the
Sullom Voe oil and gas terminal in Shetland.
North America
Our upstream activities in North America take place in four main areas:
deepwater Gulf of Mexico, Lower 48 states, Alaska and Canada. For
further information on BP’s activities in connection with its
responsibilities following the Deepwater Horizon oil spill, see page 38.
BP has around 620 lease blocks in the deepwater Gulf of Mexico, more
than any other company, and operates four production hubs.
• In 2013 BP started up an additional three rigs in the Gulf of Mexico,
and by the end of the year had ten rigs in operation.
• In April the Atlantis North expansion Phase 1 major project (BP 56%)
started up.
• In April we completed the sale of our interest in the Freedom (BP
31.5%) field in the Gulf of Mexico to Ecopetrol America.
• In April the decision was taken not to move forward with the existing
plan for the Mad Dog Phase 2 project in the deepwater Gulf of Mexico
as market conditions and industry cost inflation made the project less
attractive than previously modelled. This decision resulted in an
impairment of $159 million. BP and its partners reviewed alternative
development concepts and the current concept being considered is a
single production host designed for future flexibility to capture
additional potential resource.
• In December BP announced it had made a significant oil discovery at
its Gila prospect (BP 80%), which it co-owns with ConocoPhillips, in
the deepwater Gulf of Mexico.
• In February 2014 the Shell-operated Mars B major project (BP 28.5%)
and the BP-operated Na Kika Phase 3 project (BP 50%) started up.
For information on the temporary suspension and mandatory debarment
notices issued by the US Environmental Protection Agency (EPA) in
November 2012 and February 2013 and related proceedings, see Legal
proceedings on page 257.
The US onshore business operates in the Lower 48 states producing
natural gas, NGLs and condensate across nine states, including
production from tight gas, coalbed methane (CBM) and shale gas assets.
During 2013 BP participated in the drilling of several hundred wells as a
non-operating partner in the Eagle Ford shale, Anadarko basin and
Fayetteville shale. In the Eagle Ford shale BP, together with the operating
partner, continued to expand its position, with around 450,000 gross
acres at the end of 2013 and nine rigs operating. Production from the
liquids-rich Anadarko basin is from over 1,000,000 gross acres, with
around 12 rigs operating, and at Fayetteville there is an average of eight
rigs running over the 145,000 gross acreage position.
In March 2014 we announced plans to establish a separate BP business
to manage our onshore oil and gas assets in the US lower 48, with the
goal of building a stronger, more competitive and sustainable business.
We expect the separate organization to be operational in early 2015.
For further information on the use of hydraulic fracturing in our shale gas
assets see page 45. BP’s onshore US crude oil and product pipelines and
related transportation assets are included in the Downstream segment
(see page 31).
In Alaska, we operate 13 North Slope oilfields (including Prudhoe Bay,
Endicott, Northstar and Milne Point) and four North Slope pipelines, and
own significant interests in six other producing fields.
• Development of the Point Thomson initial production facility project
continued throughout 2013. Engineering design is substantially
complete, construction of field infrastructure is in progress and
fabrication of the four main process modules has commenced. Overall,
the project is on track. BP holds a 32% working interest in the Point
Thomson field, and ExxonMobil is the operator.
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• In June BP announced plans to add $1 billion of new investment over
five years beginning 2015 in the Alaska North Slope fields by adding
two additional drilling rigs, one each in 2015 and 2016. Changes in the
state’s oil tax statute helped to enable this increased investment. In
addition, BP secured support from the other working interest owners
at Prudhoe Bay to begin evaluating an additional $3 billion of new
development opportunities, including facility expansions, a new well
pad, and expansion of two existing well pads.
• BP continued to work jointly with ExxonMobil, ConocoPhillips and
TransCanada throughout 2013 to advance the Alaska LNG project. In
February 2013 a lead concept for the project was announced,
consisting of a North Slope gas treatment plant, an 800-mile
(approximately) pipeline to tidewater and a three-train liquefaction
facility, with an estimated capacity of 3bcf/d (15-18 million tonnes per
annum). An initial summer field season to collect data that will support
filing of necessary regulatory permits was completed. In October
selection of the lead site for the liquefaction facility was announced as
Nikiski, Alaska, located on the south-central Alaskan coast. In January
2014 BP, ExxonMobil, ConocoPhillips and TransCanada signed a heads
of agreement (HOA) with the State of Alaska enabling state
participation in the $45 – $65 billion Alaska LNG project. The HOA sets
out guiding principles for the parties to negotiate project-enabling
contracts once enabling legislation is passed and provides a road map
for state equity ownership in the project.
• In May BP and its partners announced they had been named winning
bidders in eight deepwater blocks offshore Brazil in the Brazilian
National Petroleum Agency’s 11th bid round. BP will be operator of
two of these blocks. Six of the blocks are in the Foz de Amazonas
basin, with the remaining two in the Potiguar and Barreirinhas basins.
• In July BP announced the completion of an agreement with Petróleo
Brasileiro S.A. (Petrobras) to farm in to five deepwater exploration and
production blocks, subject to government and regulatory approvals.
The blocks are in the deepwater Potiguar basin located in the Brazilian
equatorial margin and in total cover an area of 3,837km2.
• In December BP confirmed the Pitu oil discovery, operated by
Petrobras, on block BM-POT-17 in the frontier deepwater of the
Potiguar basin. BP’s farm-in to a 40% interest in this block is subject to
final regulatory approvals.
• In December BP announced the Pitanga exploration well on block
BM-CAL-13 in the Camamu-Almada basin offshore Brazil had
encountered oil shows but no commercial quantities of oil or gas. This
result will cause BP to relinquish the block and triggered a write-off of
$216 million related to the costs of drilling the well, as well as a write-
off of $845 million associated with the value allocated to this block as
part of the accounting related to the acquisition of Devon Energy’s
interest in the block announced in 2010.
• In January 2014 we completed the sale of our interest in the Polvo oil
field (BP 60%) in Brazil to HRT Oil & Gas Ltda for $135 million.
Also in Alaska, BP owns a 48.4% interest in the Trans-Alaska Pipeline
System (TAPS). The TAPS transports crude oil from Prudhoe Bay on the
Alaska North Slope to the port of Valdez in south-east Alaska.
In Argentina, Bolivia and Chile, BP conducts activity through Pan
American Energy LLC (PAE), an equity-accounted joint venture with
Bridas Corporation, in which BP has a 60% interest.
• In April 2012 the two non-controlling owners of TAPS, Koch
(3.08%) and Unocal (1.37%) gave notice to BP, ExxonMobil
(21.1%) and ConocoPhillips (29.1%) of their intention to withdraw as
an owner of TAPS. The transfer of Koch’s interest to the remaining
owners (BP, ExxonMobil and ConocoPhillips) was agreed and approved
by regulatory authorities, and closed in July with an effective date of
August 2012. The remaining owners and Unocal have not yet reached
agreement regarding the terms for the transfer of Unocal’s interest in
TAPS and are currently engaged in litigation.
• In September 2012 BP, ExxonMobil and ConocoPhillips entered into
two settlement agreements on the pooling of costs on TAPS. In July
the Federal Energy Regulatory Commission (FERC) issued an order
approving the two settlement agreements, and implementing cost
pooling between TAPS owners under the terms of the settlement
agreements.
In Canada, BP is currently focused on oil sands development and intends
to use in situ steam-assisted gravity drainage (SAGD) technology, which
uses the injection of steam into the reservoir to warm the bitumen so
that it can flow to the surface through producing wells. We hold interests
in three oil sands leases through the Sunrise Oil Sands and Terre de
Grace partnerships and the Pike Oil Sands joint operation. In addition, we
have significant exploration interests in the Canadian Beaufort Sea. The
award of four offshore leases in Nova Scotia that were successfully bid
for in 2012 was completed in 2013.
• Phase 1 of the Sunrise Oil Sands SAGD development, in which we
have a 50% non-operated interest, is under construction and is
expected to commence operations in late 2014. The production
capacity of Sunrise Phase 1 is expected to be 60mb/d of bitumen.
• A major seismic programme on the Nova Scotia exploration leases is
planned for the summer of 2014. The focus of the seismic programme
will be to shoot 3D seismic on the 14,000km2 lease area in depths
ranging from 100 metres to 3,500 metres.
South America
In South America, BP has upstream activities in Brazil, Argentina, Bolivia,
Chile, Uruguay and Trinidad & Tobago.
In Brazil, BP has interests in 24 exploration and production concessions,
six of which are operated by BP, across six basins. Five of these
concessions are subject to government and regulatory approvals.
• In March BP announced the completion of a successful flow test of the
Itaipu-1A well, offshore Brazil. This activity was part of the ongoing
appraisal programme and indicates that commercially viable flow rates
can be achieved from the BP-operated Itaipu discovery, located in the
deepwater sector of the Campos basin.
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In Uruguay, BP has interests in three offshore deepwater exploration
blocks: blocks 11 and 12 in the Pelotas basin and block 6 in the Punta del
Este basin, together covering an area of almost 26,000km2. The PSAs
provide that BP will hold a 100% interest in the blocks and the
Uruguayan state oil company, ANCAP, will have a right to participate in
up to 30% of any discoveries. BP is preparing to undertake its
commitment to acquire over 13,000km2 of 3D seismic data and 3,000km
of 2D seismic data during the first exploration period which ends in
December 2015.
In Trinidad & Tobago, BP holds licences covering 1,806,000 acres
offshore of the east and north-east coast. Facilities include 13 offshore
platforms and one onshore processing facility. Production is comprised of
oil, gas and associated liquids.
BP has a shareholding in Atlantic LNG (ALNG), an LNG liquefication plant,
in Trinidad & Tobago that averages 39% across four LNG trainsa with a
combined capacity of 21 million tonnes per annum. BP sells gas to each
of the LNG trains, supplying 100% of the gas for train 1, 50% for train 2,
75% for train 3 and around 67% of the gas for train 4. All of the LNG
from Atlantic train 1 and most of the LNG from trains 2 and 3 is sold to
third parties in the US and Europe under long-term contracts. BP’s equity
LNG entitlement from trains 2, 3 and 4 is marketed via BP’s LNG
marketing and trading function to markets in the US, UK, Spain and
South America.
Africa
BP’s upstream activities in Africa are located in Angola, Algeria, Libya,
Morocco, Egypt and Namibia.
BP is present in nine major deepwater licences offshore Angola and is
operator in four of these.
• Production from the Plutão, Saturno, Vénus and Marte (PSVM)
development area in Block 31, offshore Angola, which started
production in late 2012, continued to increase as planned, reaching a
maximum rate of just over 150mb/d in 2013.
• In October we had an oil and gas discovery in the pre-salt play of
Angola in Block 20 (BP 30%), operated by Cobalt International Energy,
Inc. This was followed by a successful drill-stem test in December.
a An LNG train is a processing facility used to liquefy and purify natural gas in the formation of
LNG.
In addition, BP has a 13.6% share in the Angola LNG project, which is
expected to receive approximately 1bcf of associated gas per day from
offshore producing blocks and to produce 5.2 million tonnes per annum
of LNG (gross), as well as related gas liquids products. The Angola LNG
project exported its first cargo of LNG in June.
In Algeria, BP is a partner with Sonatrach and Statoil in the In Salah (BP
33.15%) and In Amenas (BP 45.89%) projects, which supply gas to the
domestic and European markets. In addition, BP has an appraisal and
exploitation agreement with Sonatrach in the Bourarhat Sud block,
located to the south-west of In Amenas. In the exploration phase this
asset is BP-operated. The Bourarhat licence has been extended until
September 2014 and BP is currently assessing its options to appraise and
potentially develop this asset. BP’s total assets in Algeria at 31 December
2013 were $3,413 million ($324 million current and $3,089 million non-
current).
• In January a terrorist attack occurred at the In Amenas joint operation
site. Following the incident, BP had a staged reduction of non-essential
workers out of Algeria as a precautionary and temporary measure.
Trains 1 and 2 have been restored to full production but Train 3
remains out of service. In March, the decision was taken to suspend
activity at Bourarhat while options to appraise and potentially develop
this asset are assessed. Ramp-down of activity was largely completed
in October.
In Libya, BP is in partnership with the Libyan Investment Authority (LIA)
to explore acreage in the onshore Ghadames and offshore Sirt basins,
covered under the exploration and production-sharing agreement (EPSA)
ratified in December 2007 (BP 85%). BP’s total assets in Libya at
31 December 2013 were $472 million ($72 million current and
$400 million non-current).
• Planning and preparation work towards our offshore exploration drilling
programme is continuing. With respect to the onshore exploration
drilling programme, a security review in June concluded that this could
not be safely and securely delivered by BP at this time. Alternative
approaches are being considered.
In Morocco, BP entered into three farm-out agreements with Kosmos
Energy covering three blocks in the Agadir Basin, offshore Morocco.
Under the terms of the agreements, one of which is still subject to
government approval, BP will acquire a non-operating interest in each of
the Essaouira Offshore (BP 45%), Foum Assaka Offshore (BP 26.325%)
and Tarhazoute Offshore (BP 45%) blocks.
In Egypt, BP and its partners currently produce 15% of Egypt’s oil
production and more than 30% of its gas production. BP’s total assets in
Egypt at 31 December 2013 were $7,638 million, of which $2,299 million
were current (see Financial statements – Note 19) and $5,339 million
were non-current.
• In July the Egyptian army chief removed the country’s then-incumbent
president, Mohamed Morsi, from power and suspended the Egyptian
Constitution. Adly Mansour, Chief Justice of the Supreme
Constitutional Court of Egypt was declared interim president. The
political and economic situation remains challenging despite aid being
pledged from neighbouring Gulf states. Our production and operations
continue and we are engaged with the government in managing our
operations.
• In September BP announced a significant gas discovery in the East Nile
Delta with the Salamat well, the deepest well ever drilled in the Nile
Delta. Salamat is the first well to be drilled in the BP-operated North
Damietta (BP 100%) offshore concession awarded in 2010.
In Namibia, BP is a non-operating partner in one deepwater block, which
is currently in the exploration phase. This block was accessed in 2012. In
December BP decided to withdraw from four deepwater blocks by not
exercising an option to increase its interest in Luderita Basin licence
0047, offshore Namibia.
Asia
In Asia, BP has activities in Western Indonesia, China, Azerbaijan, Oman,
Abu Dhabi, India and Iraq.
In Western Indonesia, BP is involved in two of Indonesia’s three LNG
centres. BP’s first operated LNG plant, Tangguh (BP 37.16%), is located
in Papua Barat. The asset comprises 14 producing wells, two offshore
platforms, two pipelines and an LNG plant with two production trains and
has a total capacity of 7.6 million tonnes of LNG per annum. Plans for a
third train remain on track, with commissioning projected to occur in
2019. Tangguh supplies LNG to customers in China, South Korea, Mexico
and Japan through a combination of long, medium and short-term
contracts.
BP also participates in Indonesia’s LNG exports through its interest in
Virginia Indonesia Company LLC (VICO), the operator of Sanga-Sanga
PSA (BP 38%) supplying gas to the Bontang LNG plant in Kalimantan.
Sanga-Sanga currently delivers around 13% of the total gas feed to
Bontang, Indonesia’s largest LNG export facility and one of the world’s
largest LNG plants with a capacity of 22 million tonnes per annum of LNG
and output of more than 18 million tonnes of LNG.
BP also participates in the Sanga-Sanga CBM PSA (BP 38%), as well as
one other CBM PSA, Tanjung IV (BP 44%), in the Barito basin of Central
Kalimantan. BP completed its exit from the Kapuas I, II and III PSAs in
May by transfer of its working interest to its respective partner in each
PSA.
In China, BP’s upstream activities in the country include deepwater
exploration in the South China Sea’s Block 42/05 (BP 40.82%), Block
43/11 (BP 40.82%) and Block 54/11 (BP 100%).
• In July BP announced that it had signed a PSA with CNOOC for Block
54/11 in the South China Sea. The new block is close to BP’s two other
existing deepwater interests.
• In December we completed the sale of our interests in the Yacheng
offshore gas field (BP 34.3%) in China for $308 million (subject to post-
closing adjustments).
In China, BP also has a 30% equity stake in the 7 million tonnes per
annum capacity Guangdong LNG regasification and pipeline project in
south-east China, making it the first foreign partner in China’s LNG import
business. The terminal is also supplied under a long-term contract with
Australia’s North West Shelf venture described below.
In Azerbaijan, BP invests more than any other foreign investor, operates
two PSAs, Azeri-Chirag-Gunashli (ACG) (BP 35.8%) and Shah Deniz
(BP 25.5%), and also holds other exploration leases.
• In 2012 further EU and US regulations concerning restrictive measures
against Iran were issued. The Shah Deniz joint operation and its gas
marketing and pipeline entities, in which Naftiran Intertrade Co. Ltd
(NICO) has an interest, were excluded from the main operative
provisions of the EU regulations as well as from the application of the
new US sanctions, and fall within the exception for certain natural gas
projects under Section 603 of the US Iran Threat Reduction and
Syria Human Rights Act of 2012. Shah Deniz continues to operate in
full compliance with EU and US law. For further information see
Further note on certain activities on page 267.
• In June the Shah Deniz consortium announced that it had selected the
Trans Adriatic Pipeline (TAP) to deliver gas volumes from the Shah
Deniz Stage 2 project to customers in Italy, Greece, Bulgaria and
Turkey. In September, the consortium announced that it had concluded
the Shah Deniz Stage 2 gas sales process with the completion of major
sales agreements with European gas purchasers totalling 10bcma over
25 years. This adds to existing agreements to sell 6bcma of gas in
Turkey. The agreements come in to force following the final
investment decision (FID) on the project, which occurred in December.
The upstream part of the Shah Deniz Stage 2 project entails drilling and
completion of 26 subsea wells, construction of two bridge-linked
platforms and new processing and compression facilities at the
onshore terminal. The FID also triggers plans to expand the South
Caucasus Pipeline (SCP) through Azerbaijan and Georgia, to construct
the Trans Antolian Gas Pipeline (TANAP) across Turkey and to
construct the TAP across Greece, Albania and into Italy.
• Additionally, the State Oil Company of Azerbaijan Republic (SOCAR)
and the Shah Deniz partners also agreed terms for extending the
Shah Deniz PSA to 2048 and, coincident with the FID, BP agreed to
purchase a 3.3% equity in Shah Deniz and SCP from Statoil, subject to
conditions that are expected to be satisfied in 2014.
• In January 2014 the West Chirag platform came online. This completes
the Chirag oil project sanctioned in 2010.
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• BP, as operator, holds a 30.1% interest in and manages the Baku-
Tbilisi-Ceyhan (BTC) oil pipeline. The 1,768-kilometre pipeline
transports oil from the BP-operated ACG oilfield and gas condensate
from the Shah Deniz gas field in the Caspian Sea, along with other
third-party oil, to the eastern Mediterranean port of Ceyhan. The BTC
pipeline has a capacity of 1mmboe/d with average throughput in 2013
of 681mboe/d.
BP is technical operator of, and currently holds a 25.5% interest in, the
693-kilometre South Caucasus Pipeline, which takes gas from Azerbaijan
through Georgia to the Turkish border and has a capacity of 134mboe/d
with average throughput in 2013 of 82mboe/d. In addition, BP operates
the Western Export Route Pipeline between Azerbaijan and the Black
Sea coast of Georgia (as operator of Azerbaijan International Operating
Company).
BP currently has appraisal programmes and development activities in
Oman.
In December BP and the Sultanate of Oman government signed a gas
sales agreement and an amended exploration and production sharing
agreement (EPSA) for the development of the Khazzan field in Block 61
with BP as operator. In February 2014 the Sultan of Oman issued a royal
decree approving the amended EPSA. The Sultanate of Oman
government acquired a 40% stake in Block 61 in February 2014 through
Makarim Gas Development LLC, a wholly-owned subsidiary of the state-
owned Oman Oil Company Exploration & Production (OOCEP).
Construction work is expected to begin in 2014 with gas production
expected to start in 2017.
In Jordan BP has decided to withdraw from the Risha concession, which
resulted in a write-off of $121 million related to the costs of exploration
drilling activities, as well as a $257-million write-off for costs relating to
the concession.
In Abu Dhabi, during 2013 we had equity interests of 9.5% and 14.67%
in onshore and offshore concessions respectively. The Abu Dhabi
onshore concession expired in January 2014 with a consequent
production impact of approximately 140mboe/d.
Also in Abu Dhabi, we have a 10% equity shareholding in the Abu Dhabi
Gas Liquefaction Company, which in 2013 supplied 5.4 million tonnes of
LNG (281 bcfe regasified).
In India, BP has a 30% interest in six oil and gas PSAs operated by
Reliance Industries Limited (RIL), a 50% interest in one operated PSA,
and is a partner with RIL in a 50:50 joint operation for the sourcing and
marketing of gas in India.
• In May RIL and its partners BP and NIKO Resources Ltd announced a
significant gas and condensate discovery in the KG D6 block off the
eastern coast of India.
• In August RIL and BP announced a new gas condensate discovery in
the deepwater block CYD5 (BP 30%) situated in the Cauvery basin, off
the east coast of India. This is the second discovery in the block.
• In August the government approved the Field Development Plan (FDP)
for the R-Series project in the KG D6 block and has reviewed the
appraisal plan for the KG D6 discovery.
• Following approval by the relevant authorities in 2012, a number of
activities are being progressed to arrest the decline in production rates
and to extend the life of the block KG D6 producing fields. These
include new work-over wells and the installation of additional
compression and water handling capacity.
• In January 2014 the Government of India issued notification of new
guidelines for pricing of domestic gas, which will be formula driven,
effective from 1 April 2014.
In Iraq, BP holds a 38% working interest and is the lead contractor in the
Rumaila technical service contract. Rumaila is one of the world’s largest
oilfields and was discovered by BP, as part of a consortium, in 1953 and
comprises five producing reservoirs.
Australasia
In Australasia, we are active in Australia and Eastern Indonesia.
In Australia, BP is one of seven partners in the North West Shelf (NWS)
venture, which has been producing LNG, pipeline gas, condensate, LPG
and oil since the 1980s. Six partners (including BP) hold an equal 16.67%
interest in the gas infrastructure and an equal 15.78% interest in the gas
and condensate reserves, with a seventh partner owning the remaining
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5.32%. BP also has a 16.67% interest in some of the NWS oil reserves
and related infrastructure. The NWS venture is currently the principal
supplier to the domestic market in Western Australia and one of the
largest LNG export projects in Asia with five LNG trains in operation. BP’s
net share of the capacity of NWS LNG trains 1-5 is 2.7 million tonnes per
annum of LNG.
BP also holds a 5.375% interest in the Jansz-lo field and 12.5% interests
in the Geryon, Orthrus and Maenad fields which are part of the Greater
Gorgon project.
BP holds a 70% interest in four deepwater offshore exploration blocks in
the Ceduna Sub Basin (this follows the farm-down of 30% of our interest
in the four blocks to Statoil in April). BP, as operator, expects to drill four
deepwater wells beginning in 2016 in this frontier exploration basin,
located within the Great Australian Bight off the coast of southern
Australia.
BP is also one of five partners in the Browse LNG venture (operated by
Woodside) and holds a 17% interest.
• In September the Browse joint operation partners decided to change
the concept from an onshore LNG plant at James Price Point to an
offshore floating LNG concept resulting in an impairment of
$251 million. The proposed development remains subject to regulatory,
joint operation and internal BP approvals.
• In September gas production commenced at the Woodside-operated
North Rankin Phase 2 compression platform, designed to extend the
life of the North West Shelf production to 2040.
In Eastern Indonesia, BP has 100% interests in two deepwater PSAs:
West Aru I and II. The PSAs are located 200 kilometres west of the Aru
island group. A seismic campaign covering 5,000km2 in the West Aru
PSAs was completed in September. In addition, BP owns a 32% interest
in the Chevron-operated West Papua I and Ill PSAs, located 120
kilometres to the south of our Tangguh LNG plant (BP 37.16% and
operator).
BP received approval from the government of the Republic of Indonesia
in November to transfer its 100% interest in the North Arafura PSA,
located on the coast of the Arafura Sea, 480 kilometres south east of the
Tangguh LNG plant.
Downstream analysis by region
The downstream business includes our global fuels, lubricants and
petrochemicals businesses. We have significant operations in Europe,
North America and Asia, and also manufacture and market our products
across Australasia, Southern Africa and Central and South America.
We made significant progress in our plans to reshape the US fuels
business, build new capability and improve technology in 2013.
Our downstream business operations are detailed below by geographical
area with associated significant events for 2013.
North America
BP is active in North America through our refineries, terminals, pipelines,
retail sites, lubricants, aviation and petrochemical plants.
• To improve production, increase capacity or reduce unit cost we built
and reconfigured major units at three refineries.
– Whiting refinery – commissioning of all major units of the Whiting
refinery modernization project was completed in December 2013.
As part of the project, we built or reconfigured almost every
process unit, including crude distillation and coking units as well as
hydro-treating sulphur recovery and coking capacity. The upgrade
increases the refinery’s heavy oil processing capability, enabling
processing of up to 80% of heavy, sour crude. Whiting’s Midwest
location provides advantaged access to heavy Canadian crudes and
access to three major geographic crude sources.
– Toledo refinery – BP-Husky Refining LLC successfully started up a
new naphtha reformer in March 2013. It is intended to improve the
plant’s efficiency and competitiveness and reduce refinery air
emissions.
– Cherry Point refinery – We completed a state-of-the-art diesel
hydrotreater and hydrogen plant in May 2013. The units enhance
our ability to meet regulations calling for lower sulphur diesel fuel.
• We continued to reshape our US fuels business by completing the
sales of the Texas City and Carson, California refineries, as well as
related logistics and marketing assets.
• Our Decatur petrochemicals paraxylene/PTA plant will be the principal
supplier for a new adjacent 432,000 ton PET resin facility of Indorama
Polymers Group, announced in August 2013.
Europe
• We announced two new proprietary petrochemicals technologies,
SaaBre and Hummingbird. Both technologies are expected to deliver
significant reductions in variable manufacturing costs and simplify the
global manufacturing process.
– SaaBre significantly reduces the cost of production of acetic acid
from syngas and avoids the need to purify carbon monoxide or
purchase methanol. SaaBre technology could also be used to
produce methanol and ethanol.
– Hummingbird simplifies the process of converting ethanol to
ethylene, a key component for the manufacture of plastics.
Hummingbird could open the way for the production of
biopolymers from bioethanol.
• We have completed the sale of six out of eight countries of our global
LPG marketing business, which sells bulk and bottled LPG products
(UK, Benelux, Austria, Poland, Turkey and South Africa). Sales of the
remaining businesses in Portugal and China are expected to be
completed in 2014.
• Our lubricants business announced a co-operation agreement with
Honda Motor Europe to be the recommended lubricants supplier for
Honda’s European franchise car dealer network.
Africa
• We announced our intention to invest more than $500 million in
southern Africa over the next five years. Around half of this
investment will be used to upgrade refinery infrastructure at SAPREF,
BP’s joint operation with Shell located in Durban. In addition, BP will
invest in Pick n PayTM retail network in South Africa and in building
and upgrading our fuel terminals to a world-class standard in
Mozambique and South Africa.
Asia
• Construction of our third PTA plant at Zhuhai in Guangdong province
of China progressed, with completion expected in late 2014.
• In December 2013 we agreed to purchase all interests held by our
partners, Mitsui Chemicals, Inc. and Mitsui & Co. Ltd. in PT Amoco
Mitsui PTA Indonesia which produces and markets PTA in the Republic
of Indonesia. This transaction completed on 28 February 2014 and is
consistent with our strategy of growing our PTA business in our chosen
markets.
• We launched the gasoline additive, Ultimate, in China. The aim is to
create new market opportunities to capture more of the passenger
car market in China.
Downstream plant capacity
The following table summarizes the BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2013.
thousand barrels per day
Crude distillation capacitiesa
Geographical area
US
Washington
Indiana
Ohio
Europe
Germany
Netherlands
Spain
Rest of world
Australia
New Zealand
South Africa
Refinery
Fuels value chain
Group interestb
%
Total
Cherry Point
Whiting
Toledo
US North West
US East of Rockies
US East of Rockies
Bayernoilc
Gelsenkirchen
Karlsruhec
Lingen
Schwedtc
Rotterdam
Castellón
Rhine
Rhine
Rhine
Rhine
Rhine
Rhine
Iberia
Bulwer
Kwinana
Whangareic
Durbanc
Australia New Zealand
Australia New Zealand
Australia New Zealand
Southern Africa
100.0
100.0
50.0
22.5
50.0
12.0
100.0
18.8
100.0
100.0
100.0
100.0
23.7
50.0
234
428
160
822
217
265
322
95
239
377
110
1,625
102
146
118
180
546
Total BP share of capacity at 31 December 2013
a Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
b BP share of equity, which is not necessarily the same as BP share of processing entitlements.
c Indicates refineries not operated by BP.
BP
share
234
428
80
742
49
132
39
95
45
377
110
847
102
146
28
90
366
1,955
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243
Petrochemicals production capacitya b
The following table summarizes the BP group’s share of petrochemicals production capacities as at 31 December 2013.
Geographical area
US
Europe
UK
Belgium
Germany
Rest of world
China
Indonesia
South Korea
Malaysia
Taiwan
Total BP share of capacity at 31 December 2013
Site
Product
Cooper River
Decaturd
Texas City
Purified terephthalic acid (PTA)
PTA
Paraxylene (PX)
Acetic acid
PX
Metaxylene
Hulld
Geel
Gelsenkirchenf
Mülheimf
Acetic acid
Acetic anhydride
PTA
PX
Olefins and derivatives
Solvents
Caojing
Chongqing
Nanjing
Zhuhai
Merak
Ulsan
Kertih
Kaohsiung
Taichung
Mai Liao
Olefins and derivatives
Acetic acid
Esters
Acetic acid
PTA
PTA
Acetic acid
Vinyl acetate monomer
Acetic acid
PTA
PTA
Acetic acid
Group interest
%
BP share of
capacity
thousand tonnes
per annumc
100.0
100.0
100.0
100.0e
100.0
100.0
100.0
100.0
100.0
100.0
50.0 to 61.0
50.0
50.0
51.0
51.0
50.0
85.0
50.0
51.0
34.0
70.0
61.4
61.4
50.0
1,300
1,000
1,100
600e
1,300
100
5,400
500
200
1,300
700
1,800b g
100b
4,600
3,300b
200b
100b
300b
1,800h
300b
300b
100b
400b
900b
500b
200b
8,400
18,400
a Petrochemicals production capacity is the proven maximum sustainable daily rate (MSDR) multiplied by the number of days in the respective period, where MSDR is the highest average daily rate ever
achieved over a sustained period.
b Includes BP share of equity-accounted entities, as indicated.
c Capacities are shown to the nearest hundred thousand tonnes per annum.
d These sites have capacity under 100,000 tonnes per annum for a speciality product (e.g. naphthalene dicarboxylate and ethylidene diacetate).
e Group interest is quoted at 100%, reflecting the capacity entitlement, which is marketed by BP.
f Due to the integrated nature of these plants with our Gelsenkirchen refinery, the income and expenditure of these plants is managed and reported through the fuels business.
g Group interest varies by product.
h BP Zhuhai Chemical Company Ltd is a subsidiary of BP, the capacity of which is shown above at 100%.
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BP Annual Report and Form 20-F 2013
Oil and gas disclosures for the group
our proved undeveloped reserves position through the year for our
subsidiaries and equity-accounted entities and for our subsidiaries alone.
Resource progression
BP manages its hydrocarbon resources in three major categories:
prospect inventory, contingent resources and proved reserves. When a
discovery is made, volumes usually transfer from the prospect inventory
to the contingent resources category. The contingent resources move
through various sub-categories as their technical and commercial
maturity increases through appraisal activity.
At the point of final investment decision, most proved reserves will be
categorized as proved undeveloped (PUD). Volumes will subsequently be
recategorized from PUD to proved developed (PD) as a consequence of
development activity. When part of a well’s proved reserves depends on
a later phase of activity, only that portion of proved reserves associated
with existing, available facilities and infrastructure moves to PD. The first
PD bookings will typically occur at the point of first oil or gas production.
Major development projects typically take one to five years from the time
of initial booking of PUD to the start of production. Changes to proved
reserves bookings may be made due to analysis of new or existing data
concerning production, reservoir performance, commercial factors and
additional reservoir development activity.
Volumes can also be added or removed from our portfolio through
acquisition or divestment of properties and projects. When we dispose of
an interest in a property or project, the volumes associated with our
adopted plan of development for which we have a final investment
decision will be removed from our proved reserves upon completion.
When we acquire an interest in a property or project, the volumes
associated with the existing development and any committed projects
will be added to our proved reserves if BP has made a final investment
decision and they satisfy the SEC’s criteria for attribution of proved
status. Following the acquisition, additional volumes may be progressed
to proved reserves from contingent resources.
Contingent resources in a field will only be recategorized as proved
reserves when all the criteria for attribution of proved status have been
met and the proved reserves are included in the business plan and
scheduled for development, typically within five years. BP will only book
proved reserves where development is scheduled to commence after
more than five years, if these proved reserves satisfy the SEC’s criteria
for attribution of proved status and BP management has reasonable
certainty that these proved reserves will be produced.
At the end of 2013 BP had material volumes of proved undeveloped
reserves held for more than five years in Trinidad and the Gulf of Mexico.
These are part of ongoing development activities for which BP has a
historical track record of completing comparable projects in these
countries. We have no proved undeveloped reserves held for more than
five years in our onshore US developments.
In each case the volumes are being progressed as part of an adopted
development plan where there are physical limits to the development
timing such as infrastructure limitations, contractual limits including gas
delivery commitments, late life compression and the complex nature of
working in remote locations.
Over the past five years, BP has annually progressed on average 19% of
our proved undeveloped reserves (accounting for disposals) to proved
developed reserves. This equates to a turnover time of about five years.
We expect the turnover time to remain at or below five years and
anticipate the volume of proved undeveloped reserves held for more than
five years to remain about the same.
In 2013 we progressed 985mmboe of proved undeveloped reserves
(532mmboe for our subsidiaries alone) to proved developed reserves
through ongoing investment in our subsidiaries’ and equity-accounted
entities’ upstream development activities. Total development
expenditure in Upstream, excluding midstream activities, was
$16,664 million in 2013 ($13,552 million for subsidiaries and
$3,112 million for equity-accounted entities). The major areas with
progressed volumes in 2013 were Angola, Australia, Azerbaijan, Iraq,
Norway, Russia, Trinidad and the US. Revisions of previous estimates for
proved undeveloped reserves are due to changes relating to field
performance or well results. The following tables describe the changes to
Subsidiaries and equity-accounted assets
volumes in mmboe
Proved undeveloped reserves at 1 January 2013
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales
Total in year proved undeveloped reserves changes
Progressed to proved developed reserves
Proved undeveloped reserves at 31 December 2013
7,526
466
333
765
2,447
(2,472)
9,065
(985)
8,080
Subsidiaries only
volumes in mmboe
Proved undeveloped reserves at 1 January 2013
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales
Total in year proved undeveloped reserves changes
Progressed to proved developed reserves
Proved undeveloped reserves at 31 December 2013
4,699
(20)
294
473
–
(70)
5,376
(532)
4,844
BP bases its proved reserves estimates on the requirement of
reasonable certainty with rigorous technical and commercial
assessments based on conventional industry practice and regulatory
requirements. BP only applies technologies that have been field tested
and have been demonstrated to provide reasonably certain results with
consistency and repeatability in the formation being evaluated or in an
analogous formation. BP applies high-resolution seismic data for the
identification of reservoir extent and fluid contacts only where there is an
overwhelming track record of success in its local application. In certain
deepwater fields BP has booked proved reserves before production flow
tests are conducted, in part because of the significant safety, cost and
environmental implications of conducting these tests. The industry has
made substantial technological improvements in understanding,
measuring and delineating reservoir properties without the need for flow
tests. To determine reasonable certainty of commercial recovery, BP
employs a general method of reserves assessment that relies on the
integration of three types of data:
1. Well data used to assess the local characteristics and conditions of
reservoirs and fluids.
2. Field scale seismic data to allow the interpolation and extrapolation of
these characteristics outside the immediate area of the local well
control.
3. Data from relevant analogous fields. Well data includes appraisal wells
or sidetrack holes, full logging suites, core data and fluid samples. BP
considers the integration of this data in certain cases to be superior to
a flow test in providing understanding of overall reservoir
performance. The collection of data from logs, cores, wireline
formation testers, pressures and fluid samples calibrated to each
other and to the seismic data can allow reservoir properties to be
determined over a greater volume than the localized volume of
investigation associated with a short-term flow test. There is a strong
track record of proved reserves recorded using these methods,
validated by actual production levels.
Governance
BP’s centrally controlled process for proved reserves estimation approval
forms part of a holistic and integrated system of internal control. It
consists of the following elements:
• Accountabilities of certain officers of the group to ensure that there is
review and approval of proved reserves bookings independent of the
operating business and that there are effective controls in the approval
process and verification that the proved reserves estimates and the
related financial impacts are reported in a timely manner.
• Capital allocation processes, whereby delegated authority is exercised
to commit to capital projects that are consistent with the delivery of
BP Annual Report and Form 20-F 2013
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the group’s business plan. A formal review process exists to ensure
that both technical and commercial criteria are met prior to the
commitment of capital to projects.
• Group audit, whose role is to consider whether the group’s system of
internal control is adequately designed and operating effectively to
respond appropriately to the risks that are significant to BP.
• Approval hierarchy, whereby proved reserves changes above certain
threshold volumes require central authorization and periodic reviews.
The frequency of review is determined according to field size and
ensures that more than 80% of the BP proved reserves base
undergoes central review every two years, and more than 90% is
reviewed centrally every four years.
BP’s vice president of segment reserves is the petroleum engineer
primarily responsible for overseeing the preparation of the reserves
estimate. He has more than 30 years of diversified industry experience
with the past nine spent managing the governance and compliance of
BP’s reserves estimation. He is a past member of the Society of
Petroleum Engineers Oil and Gas Reserves Committee, a sitting member
of the American Association of Petroleum Geologists Committee on
Resource Evaluation and chair of the bureau of the United Nations
Economic Commission for Europe Expert Group on Resource
Classification.
No specific portion of compensation bonuses for executive directors and
senior management is directly related to proved reserves targets.
Additions to proved reserves is one of several indicators by which the
performance of the Upstream segment is assessed by the remuneration
committee for the purposes of determining compensation bonuses for
the executive directors. Other indicators include a number of financial and
operational measures.
BP’s variable pay programme for the other senior managers in the
Upstream segment is based on individual performance contracts.
Individual performance contracts are based on agreed items from the
business performance plan, one of which, if chosen, could relate to
proved reserves.
Compliance
International Financial Reporting Standards (IFRS) do not provide specific
guidance on reserves disclosures. BP estimates proved reserves in
accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant
Compliance and Disclosure Interpretations (C&DI) and Staff Accounting
Bulletins as issued by the SEC staff.
By their nature, there is always some risk involved in the ultimate
development and production of proved reserves including, but not limited
to: final regulatory approval; the installation of new or additional
infrastructure, as well as changes in oil and gas prices; changes in
operating and development costs; and the continued availability of
additional development capital. All the group’s proved reserves held in
subsidiaries and equity-accounted entities with the exception of those
proved reserves held by our Russian equity-accounted entity, Rosneft are
estimated by the group’s petroleum engineers.
DeGolyer & MacNaughton (D&M), an independent petroleum
engineering consulting firm, has estimated the net proved crude oil,
condensate, natural gas liquids (NGLs) and natural gas reserves, as of
31 December 2013, of certain properties owned by Rosneft. The
properties evaluated by D&M account for 100% of Rosneft’s net proved
reserves as of 31 December 2013. The net proved reserves estimates
prepared by D&M were prepared in accordance with the reserves
definitions of Rule 4-10(a)(1)-(32) of Regulation S-X. All reserves
estimates involve some degree of uncertainty. BP has filed D&M’s
independent report on its reserves estimates as an exhibit to this
document.
Our proved reserves are associated with both concessions (tax and
royalty arrangements) and agreements where the group is exposed to
the upstream risks and rewards of ownership, but where our entitlement
to the hydrocarbons is calculated using a more complex formula, such as
with PSAs. In a concession, the consortium of which we are a part is
entitled to the proved reserves that can be produced over the licence
period, which may be the life of the field. In a PSA, we are entitled to
recover volumes that equate to costs incurred to develop and produce
the proved reserves and an agreed share of the remaining volumes or the
economic equivalent. As part of our entitlement is driven by the monetary
246
BP Annual Report and Form 20-F 2013
amount of costs to be recovered, price fluctuations will have an impact
on both production volumes and reserves.
We disclose our share of proved reserves held in equity-accounted
entities (joint ventures and associates), although we do not control these
entities or the assets held by such entities.
BP’s estimated net proved reserves and proved
reserves replacement
Eighty-three per cent of our total proved reserves of subsidiaries at
31 December 2013 were held through joint operations (82% in 2012),
and 31% of the proved reserves were held through such joint operations
where we were not the operator (31% in 2012).
Estimated net proved reserves of liquids at 31 December 2013a b c
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
169
163
1,297
–
29
320
320
57
2,355
3,510
5,865
380
55
907
188
45
195
202
22
1,994
2,211
4,205
million barrels
Total
549
218
2,204d
188
74e
515
522
79
4,349
5,721f
10,070
Estimated net proved reserves of natural gas at 31 December 2013a b
UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
Total
billion cubic feet
643
364
7,122
10
3,109
961
1,519
3,932
17,660
5,837
23,497
314
39
2,825
–
6,116
1,807
3,671
1,755
16,527
5,951
22,478
957
403
9,947
10
9,225g
2,768
5,190
5,687
34,187
11,788h
45,975
Net proved reserves on an oil equivalent basis
Subsidiaries
Equity-accounted entities
Total
million barrels of oil equivalent
Developed
Undeveloped
Total
5,399
4,517
9,916
4,844
3,236
8,080
10,243
7,753
17,996
a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the
royalty owner has a direct interest in the underlying production and the option and ability to make
lifting and sales arrangements independently, and include non-controlling interests in
consolidated operations. We disclose our share of reserves held in joint ventures and associates
that are accounted for by the equity method although we do not control these entities or the
assets held by such entities.
b The 2013 marker prices used were Brent $108.02/bbl (2012 $111.13/bbl and 2011 $110.96/bbl)
and Henry Hub $3.66/mmBtu (2012 $2.75/mmBtu and 2011 $4.12/mmBtu).
c Liquids include crude oil, condensate, natural gas liquids and bitumen.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 72 million barrels on
which a net profits royalty will be payable over the life of the field under the terms of the BP
Prudhoe Bay Royalty Trust.
e Includes 21 million barrels of crude oil in respect of the 30% non-controlling interest in BP
Trinidad and Tobago LLC.
f Includes 23 million barrels of crude oil in respect of the 0.47% non-controlling interest in Rosneft
held assets in Russia.
g Includes 2,685 billion cubic feet of natural gas in respect of the 30% non-controlling interest in
BP Trinidad and Tobago LLC.
h Includes 41 billion cubic feet of natural gas in respect of the 0.44% non-controlling interest in
Rosneft held assets in Russia.
Proved reserves replacement
Total hydrocarbon proved reserves, on an oil equivalent basis including
equity-accounted entities, comprised 17,996mmboe (10,243mmboe for
subsidiaries and 7,753mmboe for equity-accounted entities) at
31 December 2013, an increase of 6% (decrease of 2% for subsidiaries
and increase of 18% for equity-accounted entities) compared with the
31 December 2012 reserves of 17,000mmboe (10,408mmboe for
subsidiaries and 6,592mmboe for equity-accounted entities). Natural
gas represented about 44% (58% for subsidiaries and 26% for equity-
accounted entities) of these reserves. The change includes a net
increase from acquisitions and disposals of 641mmboe (200mmboe net
decrease for subsidiaries and 841mmboe net increase for equity-
accounted entities). Net divestments in our subsidiaries occurred in the
UK, the US, China and Canada. We had sales and purchases as a
consequence of our divestment of TNK-BP and acquisition of Rosneft.
The proved reserves replacement ratio is the extent to which
production is replaced by proved reserves additions. This ratio is
expressed in oil equivalent terms and includes changes resulting from
revisions to previous estimates, improved recovery, and extensions and
discoveries. For 2013, the proved reserves replacement ratio excluding
acquisitions and disposals was 129% (77% in 2012 and 103% in 2011)
for subsidiaries and equity-accounted entities, 105% for subsidiaries
alone and 164% for equity-accounted entities alone. Including the net
growth in our Russian portfolio as a result of the change in our holdings,
but excluding other acquisitions and disposals, the reserves
replacement ratio on a combined basis was 199%. The net growth in
our Russian portfolio relates only to equity-accounted entities (the
transaction we completed during the year resulted in the disposal of our
interest in TNK-BP and the acquisition of an interest in Rosneft).
Therefore the split of this ratio between subsidiaries and
equity-accounted entities is as follows. For subsidiaries alone it is
BP’s net production by major field – liquids
105%, the same amount as disclosed above. For equity-accounted
entities alone it is 334%. BP reported its share of production and
reserves for TNK-BP until the transaction completed on 21 March 2013,
and this is reflected in the equity-accounted entities and group ratios
disclosed above.
In 2013 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted to
1,564mmboe (747mmboe for subsidiaries and 817mmboe for equity-
accounted entities), through revisions to previous estimates, improved
recovery from, and extensions to, existing fields and discoveries of new
fields. The subsidiary additions through improved recovery from, and
extensions to, existing fields and discoveries of new fields were in
existing developments where they represented a mixture of proved
developed and proved undeveloped reserves. Volumes added in 2013
principally resulted from the application of conventional technologies.
The principal proved reserves additions in our subsidiaries were in
Angola, Azerbaijan, Indonesia, Iraq, Oman, India and Trinidad. We had
material proved reserves reductions in the UK and the US due to
changes in activity and performance updates. The principal reserves
additions in our equity-accounted entities were in Argentina and Russia.
Fifteen per cent of our proved reserves are associated with PSAs. The
countries in which we operated under PSAs in 2013 were Algeria,
Angola, Azerbaijan, Egypt, India, Indonesia, Oman and a non-material
volume in Trinidad. In addition, the technical service contract (TSC)
governing our investment in the Rumaila field in Iraq functions as a PSA.
The Abu Dhabi onshore concession expired in January 2014 with a
consequent reduction in production of approximately 140mboe/d. The
group holds no other licences due to expire within the next three years
that would have a significant impact on BP’s reserves or production.
For further information on our reserves see page 207.
Subsidiaries
UKb
Total UK
Norwayb
Total Rest of Europe
Total Europe
Alaskab
Total Alaska
Lower 48 onshoreb
Gulf of Mexico deepwaterb
Total Gulf of Mexico deepwater
Total US
Canadab
Total Rest of North America
Total North America
Field or area
ETAPc
Foinaven (BP-operated)
Other
Various
Greater Prudhoe Bay (BP-operated)
Kuparuk
Milne Point (BP-operated)
Other
Various
Great White
Thunder Horse (BP-operated)
Atlantis (BP-operated)
Mad Dog (BP-operated)
Mars
Na Kika (BP-operated)
Horn Mountain (BP-operated)
King (BP-operated)
Other
Various (BP-operated)
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thousand barrels per day
BP net share of productiona
2013
2012
2011
22
17
22
61
34
34
96
73
36
16
12
11
14
61
86
23
23
109
77
36
15
11
22
26
65
113
32
32
145
78
39
19
17
137
139
153
56
23
27
40
18
14
28
–
–
20
170
363
–
–
363
60
19
49
23
9
15
21
6
14
35
191
390
1
1
391
69
9
77
34
8
19
14
8
15
47
231
453
2
2
455
BP Annual Report and Form 20-F 2013
247
BP’s net production by major field – liquids — continued
Subsidiaries
Colombiab
Trinidad & Tobago
Brazilb
Total South America
Angola
Total Angola
Egypt
Total Egypt
Algeriab
Total Africa
Azerbaijanb
Total Azerbaijan
Western Indonesia
Iraq
Other
Total Rest of Asiab
Total Asia
Australia
Other
Total Australasia
Total subsidiariesd
Equity-accounted entities (BP share)
TNK-BP (Russia, Venezuela, Vietnam)b e
Rosneft (Russia, Canada, Venezuela, Vietnam)b f
Abu Dhabig
Argentina
Bolivia
Venezuelab
Other
Total equity-accounted entities
Total subsidiaries and equity-accounted entities
Field or area
Various (BP-operated)
Various (BP-operated)
Polvo
Greater Plutonio (BP-operated)
Kizomba C Dev
Dalia
Girassol FPSO
Pazflor
PSVM
Other
Gupco
Other
Various
Azeri-Chirag-Gunashli (BP-operated)
Other
Various
Rumaila
Various
Various
Various
Various
Various
Various
Various
Various
Various
Various
thousand barrels per day
BP net share of productiona
2013
2012
2011
–
23
7
30
59
9
11
11
32
24
34
–
21
7
28
59
9
11
11
29
1
29
1
31
7
39
51
21
12
12
5
–
22
180
149
123
29
9
38
7
32
9
41
12
34
11
45
22
225
202
190
83
13
96
1
39
5
141
141
23
2
25
82
10
92
1
39
7
139
139
24
3
27
86
8
94
2
31
11
138
138
23
2
25
879
896
992
187
650
231
63
2
–
1
877
–
216
65
1
–
1
871
–
209
74
–
10
1
1,134
2,013
1,160
2,056
1,165
2,157
a Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b In 2013, BP divested its interests in TNK-BP, its interests in the Harding, Devenick, Maclure, Braes and Braemar fields in the North Sea and its interests in the US onshore Moxa upstream operation in
Wyoming. It also acquired an interest in Rosneft. In 2012, BP divested its interests in the Gulf of Mexico Marlin, Dorado, King, Horn Mountain, Holstein, Ram Powell and Diana Hoover assets, a portion
of its interest in the Gulf of Mexico Mad Dog asset, its interests in the US onshore Jonah and Pinedale upstream operation in Wyoming, and associated gas gathering system, its interests in the
Canadian natural gas liquid business, its interests in the Alba and Britannia fields in the UK North Sea, its interests in the Draugen field in the Norwegian Sea, and TNK-BP disposed of its interests in
OJSC Novosibirskneftegaz, with interests in Novosibirsk region, Omsk region, and Irkutsk region, and its interests in OJSC Severnoeneftegaz, with interests in Novosibirsk region. BP also increased its
interest in the US onshore Eagle Ford Shale in south Texas, its interests in certain UK North Sea assets, and in certain US Alaska assets. In 2011, BP sold its holdings in Venezuela and Vietnam to
TNK-BP. It also made acquisitions in India through a joint arrangement with Reliance, Brazil and additional volumes in the Gulf of Mexico and UK North Sea. BP divested its holdings in Pompano along
with other interests in the Gulf of Mexico, Tuscaloosa and interests in South Texas in the US onshore, a portion of our interest in the Azeri-Chirag-Gunashli development in Azerbaijan, Wytch Farm in
the UK, our interests in the REB field in Algeria, and the remainder of our interests in Colombia and Pakistan.
c Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell.
d Includes 5.5 net mboe/d of NGLs from processing plants in which BP has an interest (2012 13.5mboe/d and 2011 28mboe/d).
e Estimated production for 2013 represents BP’s share of TNK-BP’s estimated production from 1 January to 20 March, averaged over the full year.
f 2013 reflects production for the period 21 March to 31 December, averaged over the full year.
g In 2013 BP held interests, through associates, in onshore and offshore concessions in Abu Dhabi, of which the onshore concession expired in 2014 and the offshore concession expires in 2018.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
248
BP Annual Report and Form 20-F 2013
BP’s net production by major field – natural gas
Subsidiaries
UKb
Total UK
Norway
Total Rest of Europe
Total Europe
Lower 48 onshoreb
Total Lower 48 onshore
Gulf of Mexico deepwaterb
Alaska
Total US
Canadab
Total Rest of North America
Total North America
Trinidad & Tobago
Total Trinidad
Colombiab
Total South America
Egypt
Total Egypt
Algeria
Total Africa
Pakistanb
Azerbaijan
Western Indonesia
Indiab
Total India
Vietnamb
Chinab
Oman
Sharjah
Total Rest of Asia
Total Asia
Field or area
Bruce/Rhum (BP-operated)
Other
Various
San Juan (BP-operated)
Jonah (BP-operated)
Anadarko
Arkoma Central
Wamsutter (BP-operated)
Arkoma East
Arkoma West
Other
Various
Various
Various
Mango (BP-operated)
Cashima/NEQB (BP-operated)
Kapok (BP-operated)
Cannonball (BP-operated)
Amherstia (BP-operated)
Serrette (BP-operated)
Savonette (BP-operated)
Immortelle (BP-operated)
Other (BP-operated)
Various
Temsah
Ha’py (BP-operated)
Taurt (BP-operated)
Denis
Other
Various
Various (BP-operated)
Various (BP-operated)
Sanga-Sanga
D1 D3
D26
Other
Various (BP-operated)
Yacheng
Various (BP-operated)
million cubic feet per day
BP net share of productiona
2013
2012
2011
25
132
157
80
80
237
529
–
129
107
159
115
110
255
15
399
414
8
8
422
561
69
142
118
141
112
98
258
20
335
355
13
13
368
603
145
141
136
122
115
109
274
1,404
1,499
1,645
114
21
134
18
176
22
1,539
1,651
1,843
11
11
13
13
14
14
1,551
1,664
1,857
119
138
358
27
257
527
545
200
50
181
305
360
56
324
367
320
95
89
308
570
464
99
296
35
327
68
26
2,221
2,097
2,193
–
–
4
2,221
2,097
2,197
30
72
50
99
193
444
117
561
–
203
55
117
38
1
156
–
34
22
25
494
494
34
88
67
138
143
470
120
590
–
158
59
253
59
1
313
–
54
14
35
633
633
74
99
61
77
133
444
114
558
73
140
59
121
25
–
146
69
70
20
41
618
618
A
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i
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a
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i
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c
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BP Annual Report and Form 20-F 2013
249
BP’s net production by major field – natural gas – continued
Subsidiaries
Australia
Total Australia
Eastern Indonesia
Total Australasia
Total subsidiariesc
Field or area
Perseus/Athena
Goodwyn
Angel
Other
Tangguh (BP-operated)
Equity-accounted entities (BP share)
TNK-BP (Russia, Venezuela, Vietnam)b d
Rosneft (Russia, Canada, Venezuela, Vietnam)b e
Angola
Argentina
Bolivia
Venezuelab
Western Indonesia
Total equity-accounted entitiesc
Total subsidiaries and equity-accounted entities
Various
Various
ALNG
Various
Various
Various
Various
million cubic feet per day
BP net share of productiona
2013
2012
2011
139
57
89
146
431
349
780
141
73
110
111
435
352
787
170
72
126
87
455
340
795
5,845
6,193
6,393
184
617
8
329
55
–
22
785
–
–
355
34
–
26
710
–
–
371
14
4
26
1,216
7,060
1,200
7,393
1,125
7,518
a Production excludes royalties due to others whether payable in cash or in kind where the royalty owner has a direct interest in the underlying production and the option and ability to make lifting and
sales arrangements independently.
b In 2013, BP divested its interests in TNK-BP, its interests in the Harding, Devenick, Maclure, Braes, Braemar and Sean fields in the North Sea, its interests in the US onshore Moxa upstream operation
in Wyoming and its interests in the Yacheng gas field in the South China Sea. It also acquired an interest in Rosneft. In 2012, BP divested its interests in the US Hugoton basin including the Jayhawk
NGL plant, its interests in the Gulf of Mexico Marlin, Dorado, King, Horn Mountain, Holstein, Ram Powell and Diana Hoover assets, a portion of its interest in the Gulf of Mexico Mad Dog asset, its
interests in the US onshore Jonah and Pinedale upstream operation in Wyoming, its interests in the Sunray and Hemphill gas processing plants in Texas, and associated gas gathering system, its
interests in the UK North Sea southern gas fields including associated pipeline infrastructure and the Dimlington terminal (including the integrated Easington terminal), and its interests in the Alba and
Britannia fields in the UK North Sea. BP also increased its interest in the US onshore Eagle Ford Shale in South Texas, and its interests in certain UK North Sea assets. In 2011, BP sold its holdings in
Venezuela and Vietnam to TNK-BP. It also made acquisitions in India through a joint operation with Reliance, in the Eagle Ford shale in North America and additional volumes in the Gulf of Mexico.
BP divested its holdings in Pompano along with other interests in the Gulf of Mexico, Tuscaloosa and interests in south Texas in the US onshore, Wytch Farm in the UK, minor volumes in Canada and
the remainder of our interests in Colombia and Pakistan.
c Natural gas production volumes exclude gas consumed in operations within the lease boundaries of the producing field, but the related reserves are included in the group’s reserves.
d Estimated production for 2013 represents BP’s share of TNK-BP’s estimated production from 1 January to 20 March, averaged over the full year.
e 2013 reflects production for the period 21 March to 31 December, averaged over the full year.
Because of rounding, some totals may not agree exactly with the sum of their component parts.
250
BP Annual Report and Form 20-F 2013
The following tables provide additional data and disclosures in relation to our oil and gas operations.
Average sales price per unit of productiona
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
US
Russiab
Rest of
Asia
Total
group
average
$ per unit of production
105.86
9.43
102.72
10.18
91.88
3.07
109.64
8.62
106.93
9.43
96.35
2.32
106.89
7.91
107.83
13.15
96.34
3.34
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
87.16
4.66
104.27
5.75
84.53
3.53
106.39
6.05
86.60
3.60
104.37
5.24
–
–
–
–
–
–
108.24
4.99
100.41
10.55
99.24
5.35
109.69
5.08
103.12
10.08
102.10
4.75
111.10
4.73
101.22
9.13
101.29
4.69
75.45
4.05
79.08
2.35
73.51
2.31
–
–
–
–
–
–
95.28
2.47
11.58
13.21
83.85
2.35
10.15
5.08
84.39
2.23
8.11
12.21
–
–
–
–
–
–
63.65
3.26
69.41
2.52
71.35
2.40
Subsidiaries
2013
Liquidsc
Gas
2012
Liquidsc
Gas
2011
Liquidsc
Gas
Equity-accounted entitiesd
2013
Liquidsc
Gas
2012
Liquidsc
Gas
2011
Liquidsc
Gas
a Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses.
b Amounts reported for Russia in 2013 include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia.
c Crude oil, condensate and natural gas liquids.
d It is common for equity-accounted entities’ agreements to include pricing clauses that require selling a significant portion of the entitled production to local governments or markets at discounted
prices.
Average production cost per unit of productiona
Subsidiaries
2013
2012
2011
Equity-accounted entities
2013
2012
2011
$ per unit of production
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
Europe
UK
Rest of
North
America
US
Russiab
Rest of
Asia
34.10
22.77
21.59
24.48
39.10
18.23
16.11
15.60
12.09
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
5.92
5.69
3.20
12.16
11.33
9.04
13.84
11.89
10.82
–
–
–
13.20
11.85
8.65
–
–
–
4.36
5.72
5.68
4.19
2.88
2.70
3.21
3.23
3.05
–
–
–
Total
group
average
13.16
12.50
10.08
5.28
5.76
5.58
A
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i
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a
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i
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a Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
b Amounts reported for Russia in 2013 include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia.
BP Annual Report and Form 20-F 2013
251
Environmental expenditure
Environmental expenditure relating to
the Gulf of Mexico oil spill
Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental remediation
provision
Additions to decommissioning provision
2013
2012
(66)
657
1,091
42
472
2,092
919
742
1,207
47
549
3,766
$ million
2011
1,838
704
819
53
512
4,595
Environmental expenditure relating to the Gulf of
Mexico oil spill
The environmental expenditure credit of $66 million relating to the Gulf
of Mexico oil spill arises primarily from the write-back of a spill response
provision. For full details of all environmental activities in relation to the
Gulf of Mexico oil spill, see Financial statements – Note 2.
Other environmental expenditure
Operating and capital expenditure on the prevention, control, abatement
or elimination of air, water and solid waste pollution is often not incurred
as a separately identifiable transaction. Instead, it forms part of a larger
transaction that 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 operating expenditure of $657 million in 2013 was lower
than in 2012 and 2011. This is primarily due to the divestment of the
Texas City and Carson refineries during 2013.
Capital expenditure in 2013 was lower than in 2012 principally due to
reduced levels of construction activity at our Whiting refinery in 2013 as
compared to 2012. All of the major new units associated with the
Whiting refinery modernization project were progressively
commissioned during 2013 with the final major unit being brought
onstream in December. Similar levels of operating and capital
expenditures are expected in the foreseeable future.
In addition to operating and capital expenditures, we also establish
provisions for future environmental remediation. Expenditure against such
provisions normally occurs in subsequent periods and is not included in
environmental operating expenditure reported for such periods.
Generally, this coincides with the commitment to a formal plan of action
or, if earlier, on divestment or on closure of inactive sites.
The extent and cost of future environmental restoration, remediation
and abatement programmes are inherently difficult to estimate. They
often depend on the extent of contamination, and the associated impact
and timing of the corrective actions required, technological feasibility
and BP’s share of liability. Though the costs of future programmes
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 be material to the group’s overall results of operations or
financial position.
Additions to our environmental remediation provision decreased in 2013
largely due to scope reassessments of the remediation plans of a
number of our sites in the US and Canada. The charge for
environmental remediation provisions in 2013 included $13 million in
respect of provisions for new sites (2012 $19 million and 2011
$12 million).
In addition, we make provisions on installation of our oil- and gas-
producing assets and related pipelines to meet the cost of eventual
decommissioning. On installation of an oil or natural gas production
facility a provision is established that represents the discounted value of
the expected future cost of decommissioning the asset.
In 2013 additions to the decommissioning provision were less than in
2012, and were driven by detailed reviews of expected future costs,
and to a lesser extent increases to the asset base. The additions in
2011 and 2012 were driven by changes in estimation and detailed
reviews of expected future costs. The majority of these additions
related to our sites in Trinidad, the Gulf of Mexico, Alaska, Angola and
the North Sea.
In 2011 and 2012, the Gulf of Mexico was impacted by the Bureau of
Ocean Energy Management, Regulation and Enforcement’s (BOEMRE)
Notice to Lessees (NTL) 2010-G05, issued in October 2010, which
requires that idle infrastructure on active leases be decommissioned
earlier than previously was required and establishes guidelines to
determine the future utility of idle infrastructure on active leases.
We undertake periodic reviews of existing provisions. These reviews
take account of revised cost assumptions, changes in decommissioning
requirements and any technological developments.
Provisions for environmental remediation and decommissioning are
usually established on a discounted basis, as required by IAS 37
‘Provisions, Contingent Liabilities and Contingent Assets’.
Provisions for environmental remediation are made when a clean-up is
probable and the amount of the obligation can be reliably estimated.
Further details of decommissioning and environmental provisions
appear in the financial statements – Note 29.
Contractual obligations
The following table summarizes the group’s principal contractual obligations at 31 December 2013, distinguishing between those for which a liability is
recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial statements –
Note 27 and more information on operating leases is given in Financial statements – Note 9.
Expected payments by period under contractual obligations
Balance sheet obligations
Borrowingsa
Finance lease future minimum lease paymentsb
Decommissioning liabilitiesc
Environmental liabilitiesc
Pensions and other post-retirement benefitsd
Off-balance sheet obligations
Operating lease future minimum lease paymentse
Unconditional purchase obligationsf
$ million
Payments due by period
Total
2014
2015
2016
2017
2018
51,393
871
20,850
3,546
24,145
100,805
19,186
232,757
251,943
8,186
80
988
861
1,916
12,031
5,188
116,856
122,044
7,307
75
731
1,277
1,904
11,294
3,790
25,387
29,177
7,275
66
699
281
1,894
10,215
2,871
16,193
19,064
6,263
63
568
267
1,633
8,794
5,607
60
865
186
1,325
8,043
2,117
12,275
14,392
1,630
10,687
12,317
2019 and
thereafter
16,755
527
16,999
674
15,473
50,428
3,590
51,359
54,949
Total
352,748
134,075
40,471
29,279
23,186
20,360
105,377
a Expected payments include interest totalling $3,736 million ($846 million in 2014, $717 million in 2015, $588 million in 2016, $468 million in 2017, $360 million in 2018 and $757 million thereafter).
252
BP Annual Report and Form 20-F 2013
b Expected payments include interest totalling $336 million ($39 million in 2014, $35 million in 2015, $33 million in 2016, $30 million in 2017, $28 million in 2018 and $171 million thereafter).
c The amounts are undiscounted. Environmental liabilities include those relating to the Gulf of Mexico oil spill, including liabilities for spill response costs.
d Represents the expected future contributions to funded pension plans and payments by the group for unfunded pension plans and the expected future payments for other post-retirement benefits.
e The future minimum lease payments are before deducting related rental income from operating sub-leases. In the case of an operating lease entered into solely by BP as the operator of a joint
operation, the amounts shown in the table represent the net future minimum lease payments, after deducting amounts reimbursed, or to be reimbursed, by joint operation partners. Where BP is not
the operator of a joint operation BP’s share of the future minimum lease payments are included in the amounts shown, whether BP has co-signed the lease or not. Where operating lease costs are
incurred in relation to the hire of equipment used in connection with a capital project, some or all of the cost may be capitalized as part of the capital cost of the project.
f Represents any agreement to purchase goods or services that is enforceable and legally binding and that specifies all significant terms. The amounts shown include arrangements to secure long-term
access to supplies of crude oil, natural gas, feedstocks and pipeline systems. In addition, the amounts shown for 2014 include purchase commitments existing at 31 December 2013 entered into
principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is discussed in Financial
statements – Note 19.
The following table summarizes the nature of the group’s unconditional purchase obligations.
Unconditional purchase obligations
Crude oil and oil products
Natural gas
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total
Total
133,774
37,005
17,005
3,208
796
22,727
18,242
2014
84,558
23,417
3,976
2,067
200
1,589
1,049
2015
13,854
5,612
3,190
794
168
1,084
685
2016
9,026
2,751
2,590
250
108
965
503
2017
6,533
1,768
2,306
97
83
1,041
447
$ million
Payments due by period
2018
5,281
1,309
2,248
—
73
1,031
745
2019 and
thereafter
14,522
2,148
2,695
—
164
17,017
14,813
232,757
116,856
25,387
16,193
12,275
10,687
51,359
The information above contains forward-looking statements, which by their nature involve risk and uncertainty because they relate to events and
depend on circumstances that will or may occur in the future and are outside the control of BP. You are urged to read the cautionary statement on
page 271 and Risk factors on page 51, which describe the risks and uncertainties that may cause actual results and developments to differ materially
from those expressed or implied by these forward-looking statements.
Regulation of the group’s business
BP’s activities, including its oil and gas exploration and production,
pipelines and transportation, refining and marketing, petrochemicals
production, trading, alternative energy and shipping activities, are
conducted in many different countries and are subject to a broad range
of EU, US, international, regional and local legislation and regulations,
including legislation that implements international conventions and
protocols. These cover virtually all aspects of BP’s activities and include
matters such as licence acquisition, production rates, royalties,
environmental, health and safety protection, fuel specifications and
transportation, trading, pricing, anti-trust, export, taxes and foreign
exchange.
The terms and conditions of the leases, licences and contracts under
which our oil and gas interests are held vary from country to country.
These leases, licences and contracts are generally granted by or
entered into with a government entity or state-owned or controlled
company and are sometimes entered into with private property owners.
Arrangements with governmental or state entities usually take the form
of licences or production-sharing agreements (PSAs), although
arrangements with the US government can be by lease. Arrangements
with private property owners are usually in the form of leases.
Licences (or concessions) give the holder the right to explore for and
exploit a commercial discovery. Under a licence, the holder bears the
risk of exploration, development and production activities and provides
the financing for these operations. In principle, the licence holder is
entitled to all production, minus any royalties that are payable in kind. A
licence holder is generally required to pay production taxes or royalties,
which may be in cash or in kind. Less typically, BP may explore for and
exploit hydrocarbons under a service agreement with the host entity in
exchange for reimbursement of costs and/or a fee paid in cash rather
than production.
PSAs entered into with a government entity or state-owned or
controlled company generally require BP to provide all the financing and
bear the risk of exploration and production activities in exchange for a
share of the production remaining after royalties, if any.
In certain countries, separate licences are required for exploration and
production activities and, in certain cases, production licences are
limited to only a portion of the area covered by the original exploration
licence. Both exploration and production licences are generally for a
specified period of time. In the US, leases from the US government
typically remain in effect for a specified term, but may be extended
beyond that term as long as there is production in paying quantities. The
term of BP’s licences and the extent to which these licences may be
renewed vary from country to country.
Frequently, BP conducts its exploration and production activities in joint
arrangements or co-ownership arrangements with other international oil
companies, state-owned or controlled companies and/or private
companies. These joint arrangements may be incorporated or
unincorporated arrangements, while the co-ownerships are typically
unincorporated. Whether incorporated or unincorporated, relevant
agreements set out each party’s level of participation or ownership
interest in the joint arrangement or co-ownership. Conventionally, all
costs, benefits, rights, obligations, liabilities and risks incurred in carrying
out joint-arrangement or co-ownership operations under a lease or licence
are shared among the joint-arrangement or co-owning parties according to
these agreed ownership interests. Ownership of joint-arrangement or
co-owned property and hydrocarbons to which the joint arrangement or
co-ownership is entitled is also shared in these proportions. To the extent
that any liabilities arise, whether to governments or third parties, or as
between the joint arrangement parties or co-owners themselves, each
joint arrangement party or co-owner will generally be liable to meet these
in proportion to its ownership interest. In many upstream operations, a
party (known as the operator) will be appointed (pursuant to a joint
operating agreement (JOA)) to carry out day-to-day operations on behalf of
the joint arrangement or co-ownership. The operator is typically one of the
joint arrangement parties or a co-owner and will carry out its duties either
through its own staff, or by contracting out various elements to third-party
contractors or service providers. BP acts as operator on behalf of joint
arrangements and co-ownerships in a number of countries where we
have exploration and production activities.
Frequently, work (including drilling and related activities) will be contracted
out to third-party service providers who have the relevant expertise and
equipment not available within the joint arrangement or the co-owning
operator’s organization. The relevant contract will specify the work to be
done and the remuneration to be paid and typically will set out how major
risks will be allocated between the joint arrangement or co-ownership and
the service provider. Generally, the joint arrangement or co-owner and the
contractor would respectively allocate responsibility for and provide
reciprocal indemnities to each other for harm caused to their respective
staff and property. Depending on the service to be provided, an oil and
gas industry service contract may also contain provisions allocating risks
and liabilities associated with pollution and environmental damage,
damage to a well or hydrocarbon reservoir and for claims from third
BP Annual Report and Form 20-F 2013
253
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parties or other losses. The allocation of those risks vary among contracts
and are determined through negotiation between the parties.
with our operations and can require corrective action at locations
where such wastes have been disposed of or released.
In general, BP is required to pay income tax on income generated from
production activities (whether under a licence or PSAs). In addition,
depending on the area, BP’s production activities may be subject to a
range of other taxes, levies and assessments, including special
petroleum taxes and revenue taxes. The taxes imposed on oil and gas
production profits and activities may be substantially higher than those
imposed on other activities, for example in Abu Dhabi, Angola, Egypt,
Norway, the UK, the US, Russia and Trinidad & Tobago.
Environmental regulation
BP has operations in around 80 countries and is subject to a wide variety of
environmental regulations concerning its products, operations and
activities. Current and proposed fuel and product specifications, emission
controls, climate change programmes and regulation of unconventional gas
extraction under a number of environmental laws may have a significant
effect on the production, sale and profitability of many of BP’s products.
There are also environmental laws that require BP to remediate and
restore areas affected by the release of hazardous substances or
hydrocarbons associated with our operations. These laws may apply to
sites that BP currently owns or operates, sites that it previously owned or
operated, or sites used for the disposal of its and other parties’ waste.
Provisions for environmental restoration and remediation are made when
a clean-up is probable and the amount of BP’s legal obligation can be
reliably estimated. The cost of future environmental remediation
obligations is often inherently difficult to estimate.
Uncertainties can include the extent of contamination, the appropriate
corrective actions, technological feasibility and BP’s share of liability. See
Financial statements – Note 29 for the amounts provided in respect of
environmental remediation and decommissioning.
A number of pending or anticipated governmental proceedings against
certain BP group companies under environmental laws could result in
monetary or other sanctions. We are also subject to environmental
claims for personal injury and property damage alleging the release of, or
exposure to, hazardous substances. The costs associated with such
future environmental remediation obligations, governmental proceedings
and claims could be significant and may be material to the results of
operations in the period in which they are recognized. We cannot
accurately predict the effects of future developments on the group, such
as stricter environmental laws or enforcement policies, or future events
at our facilities, and there can be no assurance that material liabilities and
costs will not be incurred in the future. For a discussion of the group’s
environmental expenditure see page 252.
A significant proportion of our fixed assets are located in the US and the
EU. US and EU environmental, health and safety regulations significantly
affect BP’s exploration and production, refining and marketing,
transportation and shipping operations. Significant legislation and
regulation in the US and the EU affecting our businesses and profitability
includes the following:
United States
• The Clean Air Act (CAA) regulates air emissions, permitting, fuel
specifications and other aspects of our production, distribution and
marketing activities. Stricter limits on sulphur in fuels will affect us in
future, as will actions on greenhouse gas (GHG) emissions and other
air pollutants. Additionally, states may have separate, stricter air
emission laws in addition to the CAA.
• The Energy Policy Act of 2005 and the Energy Independence and
Security Act of 2007 affect our US fuel markets by, among other
things, imposing renewable fuel mandates and imposing GHG
emissions thresholds for certain renewable fuels. States such as
California also impose additional fuel carbon standards.
• The Clean Water Act regulates wastewater and other effluent
discharges from BP’s facilities, and BP is required to obtain discharge
permits, install control equipment and implement operational controls
and preventative measures.
• The Resource Conservation and Recovery Act regulates the
generation, storage, transportation and disposal of wastes associated
254
BP Annual Report and Form 20-F 2013
• The Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) can, in certain circumstances, impose the entire
cost of investigation and remediation on a party who owned or
operated a site contaminated with a hazardous substance, or arranged
for disposal of a hazardous substance at a site. BP has incurred, or is
likely to incur, liability under the CERCLA or similar state laws,
including costs attributed to insolvent or unidentified parties. BP is also
subject to claims for remediation costs under other federal and state
laws, and to claims for natural resource damages under the CERCLA,
the Oil Pollution Act of 1990 (OPA 90) (discussed below) and other
federal and state laws. CERCLA also requires hazardous substance
release notification.
• The Toxic Substances Control Act regulates BP’s import, export and
sale of new chemical products.
• The Occupational Safety and Health Act imposes workplace safety and
health requirements on BP operations along with significant process
safety management obligations.
• In May 2012, the US adopted the UN Global Harmonization System for
hazard classification and labelling of chemicals and products, with the
modification of the Occupational Safety & Health Administration
Hazard Communication Standard. Manufacturers are required to
reclassify both Substance and Mixture safety and data sheets (SDS) by
1 June 2015 and to have trained employees on the new label elements
(pictograms) and SDS format by 1 December 2013. BP completed the
training for its employees by the 1 December 2013 deadline.
• The Emergency Planning and Community Right-to-Know Act requires
emergency planning and hazardous substance release notification as
well as public disclosure of our chemical usage and emissions.
• The US Department of Transportation (DOT) regulates the transport of
BP’s petroleum products such as crude oil, gasoline, petrochemicals
and other hydrocarbon liquids.
• The Maritime Transportation Security Act (MTSA), the DOT Hazardous
Materials (HAZMAT) and the Chemical Facility Anti-Terrorism Standard
(CFATS) regulations impose security compliance regulations on around
50 BP facilities. These regulations require security vulnerability
assessments, security risk mitigation plans and security upgrades,
increasing our cost of operations.
OPA 90 is implemented through regulations issued by the US
Environmental Protection Agency (EPA), the US Coast Guard, the DOT,
the Occupational Safety and Health Administration, the Bureau of Safety
and Environmental Enforcement and various states. Alaska and the west
coast states currently have the most demanding state requirements.
As a consequence of the Deepwater Horizon incident BP has become
subject to claims under OPA 90 and other laws and has established a
$20-billion trust fund for legitimate state and local government response
claims, final judgments and settlement claims, legitimate state and local
response costs, natural resource damages and related costs and legitimate
individual and business claims (see Gulf of Mexico oil spill on page 38). BP
is also subject to natural resource damages claims, claims for civil penalties
under the Clean Water Act, and numerous civil lawsuits by individuals,
businesses and governmental entities. The ultimate costs for these claims
cannot be determined at this time. For further disclosures relating to the
consequences of the 2010 Deepwater Horizon oil spill, see Legal
proceedings on page 257.
BP has also been in discussions with the EPA regarding alleged
CAA violations at the Toledo refinery and the EPA has alleged certain
CAA violations at the Cherry Point refinery and the Carson refinery (which
BP sold to Tesoro Corporation on 1 June 2013).
European Union
• The 2008 EU Climate and Energy Package, includes the EU Emissions
Trading System (EU ETS) Directive and the Renewable Energy
Directive (see Greenhouse gas regulation on page 44). In January
2014, the European Commission proposed a new Climate and Energy
Package for the period up to 2030. Under the third trading period of the
EU ETS – ‘Phase III’ – which started on 1 January 2013, the EU ETS
has been expanded to include, among others, the petrochemical
sector. Installations in sectors at risk of “carbon leakage” (i.e.
production transfers out of the EU ETS trading area) are partially
compensated with free allocation of emission allowances based on
benchmarks used to calculate the number of free emissions per
installation. There is no free allocation for electricity generation and
production installations; instead these allowances are auctioned off to
market participants.
• The Energy Efficiency Directive (EED) was adopted in 2012. It requires
EU Member States to implement an indicative 2020 energy saving
target and apply a framework of measures as part of a national energy
efficiency programme. Such measures include mandatory industrial
energy efficiency surveys, to obtain data on both new plants and the
replacement of large plants.
• The Industrial Emissions Directive (IED) provides the framework for
granting permits for major industrial sites. It imposes emission limit
values, based on the use of Best Available Techniques (BAT), for
discharges to air and water. The emission limit values are informed by
the sector specific and cross-sector BAT Reference Documents
(BREFs), which are reviewed periodically. The outcome of the review
of several BREFs relevant to our major sites is expected in 2014. The
IED transposition and output from the BREF revisions may result in
requirements for further emission reductions at our EU sites.
• The European Commission’s Air Policy Review and the related work on
revisions to the Gothenburg Protocol and National Emissions Ceiling
Directive (NECD) may lead to national ceilings for emissions of a
variety of air pollutants in order to achieve EU-wide health and
environmental improvement targets. Along with the proposed Directive
on medium combustion plants, this may result in requirements for
further emission reductions at BP’s EU sites.
• The implementation of the Water Framework Directive and the
Environmental Quality Directive may mean that BP has to take further
steps to manage water discharges from its refineries and chemical
plants in the EU.
• The EU regulation on ozone depleting substances (ODS), which
implements the Montreal Protocol (Protocol) on ODS requires BP to
reduce the use of ODS and phase out use of certain ODSs. BP
continues to replace ODS in refrigerants and/or equipment, in the EU
and elsewhere, in accordance with the Protocol and related legislation.
Methyl bromide (an ODS) is a minor by-product in the production of
purified terephthalic acid in our petrochemicals operations. The
progressive phase-out of methyl bromide uses may result in future
pressure to reduce our emissions of methyl bromide. In addition, the
impending adoption of a revised regulation to phase out the use of
fluorinated gases, including hydrofluorocarbons (HFCs) may have an
impact on some of BP’s operations.
• The EU Fuel Quality Directive affects our production and marketing of
transport fuels. Revisions adopted in 2009 mandate reductions in the
life cycle GHG emissions per unit of energy and tighter environmental
fuel quality standards for petrol and diesel.
• The EU Registration, Evaluation and Authorization of Chemicals
(REACH) Regulation requires registration of chemical substances,
manufactured in, or imported into, the EU in quantities greater than
1 tonne per annum per legal entity, together with the submission of
relevant hazard and risk data. REACH affects our refining,
petrochemicals, exploration and production, biofuels, lubricants and
other manufacturing or trading/import operations. Having completed
registration of all the substances that we were required to submit by
the regulatory deadlines of 1 December 2010 (>1,000 tonnes per
annum/legal entity) and 31 May 2013 (100-1,000 tonnes per annum/
legal entity), we are now preparing registration dossiers for substances
manufactured or imported in amounts in the range 1-100 tonnes per
annum/legal entity that are due to be submitted before 31 May 2018.
Some substances registered previously, including substances supplied
to us by third parties for our use, are now subject to thorough
evaluation and/or potential authorization/restriction procedures by the
European Chemicals Agency and EU Member state authorities.
Legislation similar to REACH is in place in Turkey, which requires the
registration of manufactured and imported chemicals.
• In addition, Europe has adopted the UN Global Harmonization System
for hazard classification and labelling of chemicals and products, which
has been fully implemented in a number of countries outside the EU,
through the Classification Labelling and Packaging (CLP) Regulation.
This requires BP to assess the hazards of all of our chemicals and
products against new criteria and will result in significant changes to
warning labels and material safety data sheets. All our European
Material Safety Data Sheets are being updated to include both REACH
and CLP information. We have also notified the European Chemicals
Agency of hazard classifications for our manufactured and imported
chemicals, for inclusion in a publicly available inventory of hazardous
chemicals. CLP will also apply to mixtures (e.g. lubricants) by 2015.
Activities covered by both CLP and REACH are subject to enforcement
activity by national regulatory authorities. Several BP entities were
already subject to inspections. All observations made were minor in
nature, and were readily rectified to the satisfaction of the authorities.
• The EU Commission has issued the Offshore Safety Directive which is
now required to be transposed into national legislation by Member
States, including the UK. Its purpose is to introduce a harmonized
regime aimed at reducing the potential environmental, health and
safety impacts of the offshore oil and gas industry throughout EU
waters. Implementation into UK legislation will involve alignment of the
regime currently operating in the UK.
Environmental maritime regulations
BP’s shipping operations are subject to extensive national and
international regulations governing liability, operations, training, spill
prevention and insurance. These include:
• In US waters, OPA 90 imposes liability and spill prevention and
planning requirements governing, among others, tankers, barges and
offshore facilities. It also mandates a levy on imported and
domestically produced oil to fund oil spill responses. Some states,
including Alaska, Washington, Oregon and California, impose additional
liability for oil spills. Outside US territorial waters, BP shipping tankers
are subject to international liability, spill response and preparedness
regulations under the UN’s International Maritime Organization,
including the International Convention on Civil Liability for Oil Pollution,
the International Convention for the Prevention of Pollution from Ships
(MARPOL) Convention, the International Convention on Oil Pollution,
Preparedness, Response and Co-operation and the International
Convention on Civil Liability for Bunker Oil Pollution Damage. In April
2010, the Hazardous and Noxious Substance (HNS) Protocol 2010, was
adopted to address issues that have inhibited ratification of the
International Convention on Liability and Compensation for Damage in
Connection with the Carriage of Hazardous and Noxious Substances by
Sea 1996 (the HNS Convention). As at 9 January 2014, there were
14 contracting states to the HNS Convention but it had not yet entered
into force.
• In April 2008, the International Maritime Organization (IMO) approved
amendments to Annex VI of the MARPOL to reduce the sulphur
content in marine fuels. Since 1 January 2012 the global limit on
sulphur content in marine fuels may not exceed 3.50%. This global
limit will be further reduced to 0.5% in 2020, provided there is enough
fuel available. Annex VI also provides for stricter sulphur emission
restrictions on ships in SOx Emission Control Areas (SECAs). EU ports
and inland waterways and the North Sea and Baltic Sea have been
covered by SECAs since 2010 imposing a sulphur content limit of
0.1%. These restrictions require the use of compliant heavy fuel oil
(HFO) or distillate, or the installation of abatement technologies on
ships. These restrictions are expected to place additional costs on
refineries producing marine fuel, including costs to dispose of sulphur,
as well as increased GHG emissions and energy costs for additional
refining.
To meet its financial responsibility requirements, BP shipping maintains
marine liability pollution insurance in respect of its operated ships to a
maximum limit of $1 billion for each occurrence through mutual
insurance associations (P&I Clubs) but there can be no assurance that a
spill will necessarily be adequately covered by insurance or that liabilities
will not exceed insurance recoveries.
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BP Annual Report and Form 20-F 2013
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Greenhouse gas regulation
Increasing concerns about climate change have led to a number of
international climate agreements and negotiations continue on defining
the scope and nature of the commitments to be entered into by those
subject to the next phase of international climate change regulation.
At the UN summit in Cancun in December 2010, the parties to the UN
Framework Convention on Climate Change (UNFCCC) entered into a
formal agreement on a package of measures to 2020. The Cancun
Agreement seeks deep cuts in global greenhouse gas (GHG) emissions
required to hold the increase in global temperature to below 2°C.
Signatories formally committed to carbon reduction targets or actions by
2020. Around 85 countries, including 69 developed economies (the EU
counted as 28 countries) and 16 developing countries, have made such
commitments currently. An additional 39 developing countries have
submitted pledges related to sectoral goals. Supporting those climate
efforts, principles were agreed for monitoring, verifying and reporting
emissions reductions; the Green Climate Fund was established to help
developing countries limit and adapt to climate change; and measures
were agreed to protect forests and transfer low-carbon technology to
poorer nations. In November 2011, parties to the UNFCCC conference in
Durban (COP17) agreed to several measures. One was a ‘roadmap’ for
negotiating a legal framework for action on climate change by 2015 that
would involve all countries by 2020 and would close the ‘ambition gap’
between existing GHG reduction pledges and what is required to achieve
the goal of limiting global temperature rise to 2°C. Another was a second
commitment period for the Kyoto Protocol, to begin immediately after the
first period. An amendment was subsequently adopted at the 2012
conference of parties (COP18) in Doha establishing a second
commitment period to run until the end of 2020. However, it will not
include the US, Canada, Japan and Russia and thus covers only about
15% of global emissions. The 2013 Warsaw meeting (COP19) agreed to
continue these processes with a view to agreeing to post-2015 and post-
2020 targets or frameworks.
Aspects of these international concerns and agreements are reflected in
national and regional measures seeking to limit GHG emissions.
Additional, more stringent, measures can be expected in the future.
These measures could increase BP’s production costs for certain
products, increase demand for competing energy alternatives or products
with lower-carbon intensity, and affect the sales and specifications of
many of BP’s products. Current measures and developments potentially
affecting BP’s businesses include the following:
• The European Union (EU) has agreed to an overall GHG reduction
target of 20% by 2020. To meet this, a ‘Climate and Energy Package’
of regulatory measures has been adopted including: national reduction
targets for emissions not covered by the EU ETS; binding national
renewable energy targets to double usage of renewable energy
sources in the EU including at least a 10% share of renewable energy
in the transport sector; a legal framework to promote carbon capture
and storage (CCS); and a revised EU ETS Phase 3. EU ETS revisions
include a GHG reduction of 21% from 2005 levels, a significant
increase in allowance auctioning, an expansion in the scope of the EU
ETS to encompass more industrial sectors and gases and no free
allocation for electricity generation or production but benchmarked free
allocation for energy-intensive and trade-exposed industrial sectors.
Finally, EU energy efficiency policy is currently implemented via
national energy efficiency action plans and the Energy Efficiency
Directive adopted in 2012. The EU recently started discussions on a
new framework for its energy and climate policies over the 2030 time
horizon which will succeed the current framework once adopted.
• Article 7a of the revised EU Fuel Quality Directive requires fuel
suppliers to reduce the life cycle GHG emissions per unit of fuel and
energy supplied in certain transport markets.
• Australia has committed to reduce its GHG emissions by at least 5%
below 2000 levels by 2020. In accordance with the Clean Energy Act
2011, Australia’s carbon price took effect on 1 July 2012 with a fixed
price of $23 Australian dollars per tonne. The fixed price phase is
scheduled to transition into a market-based price (emissions trading
scheme) by 1 July 2016. BP refineries and its share of the North West
Shelf Project are covered entities within the Clean Energy Act 2011
and are liable for carbon dioxide-equivalent emissions. With Australia’s
change of federal government in September 2013, there is significant
256
BP Annual Report and Form 20-F 2013
uncertainty that exists in relation to the future of the Carbon Pricing
Mechanism provided for under the Clean Energy Act 2011. BP
Australia continues to monitor this situation.
• New Zealand has agreed to cut GHG emissions by at least 5% below
1990 levels by 2020, with additional reduction conditioned on a
comprehensive global agreement for emissions reductions coming into
force. New Zealand’s emission trading scheme (NZ ETS) commenced
on 1 July 2010 for transport fuels, industrial processes and stationary
energy. New Zealand also employs a portfolio of mandatory and
voluntary complementary measures aimed at GHG reductions. New
Zealand made its recent commitments for GHG reduction under the
UN Framework Convention rather than the Kyoto Protocol.
• In the US, with the potential for passing comprehensive climate
legislation remaining very unlikely, the US Environmental Protection
Agency (EPA) continues to pursue regulatory measures to address
GHGs under the Clean Air Act (CAA).
–
In late 2009, the EPA released a GHG endangerment finding to
establish its authority to regulate GHG emissions under the CAA.
– Subsequent to this, the EPA finalized regulations imposing light
duty vehicle emissions standards for GHGs.
– The EPA finalized the initial GHG mandatory reporting rule
(GHGMRR) in 2009 and continues to make amendments to the
rule. Reports under the GHGMRR are due annually. The majority
of BP’s US businesses are affected by the GHGMRR and
submitted their GHG emissions reports to the EPA under the
GHGMRR on or before the required deadlines. In addition to direct
emissions from affected facilities, producers and importers/
exporters of petroleum products, certain natural gas liquids and
GHGs are required to report product volumes and notional GHG
emissions as if these products were fully combusted. The EPA
has released direct emissions data since 2011, and in 2013
released aggregated site product emissions data. Certain
confidential business information protections remain for both
direct and product emissions data reported.
– The EPA finalized permitting requirements for new or modified
–
large GHG emission sources in 2010, with initial regulations taking
effect in January 2011, the second phase taking effect on 1 July
2011 and the third phase finalized on 29 June 2012.
In a legal settlement with environmental advocacy groups, the EPA
committed to propose a GHG New Source Performance Standards
(NSPS) for GHG emissions from refineries by December 2011 and
to finalize the NSPS by November 2012. These deadlines were not
met and the new refinery NSPS deadlines were not proposed by
the administration when the electric generating unit (EGU) GHG
EGU NSPS deadlines were announced in a Climate Policy Directive
in June 2013.
– Legal challenges to the EPA’s efforts to regulate GHG emissions
through the CAA continue, including before the US Supreme Court
in the 2013-2014 term, along with active political debate with the
final content and scope of GHG regulation in the US remaining
uncertain.
• A number of additional state and regional initiatives in the US will affect
our operations. Of particular significance, California implemented a low-
carbon fuel standard in 2010 and is seeking to reduce GHG emissions
to 1990 levels by 2020 and to reduce the carbon intensity of transport
fuel sold in the state. Legal challenges resulted in a pause for 2014
carbon intensity targets at the 2013 level. Whilst these legal challenges
continue, the preliminary injunction stopping implementation was lifted
and implementation of the programme continues. The California cap
and trade programme started in January 2012 with the first auctions of
carbon allowances held in November 2012 and obligations
commencing in 2013.
• Canada has established an action plan to reduce emissions to 17%
below 2005 levels by 2020 and the national government continues to
seek a co-ordinated approach with the US on environmental and energy
objectives. Additionally, Canada’s highest emitting province, Alberta, has
been running a market mechanism to reduce GHG emissions since
2007. Controversy, partially driven by perceived GHG intensity regarding
Canadian oil sand produced crude, continues with some jurisdictions
contemplating policies to restrict or penalize the use of such crude.
• China has committed to reducing carbon intensity of GDP 40-45%
below 2005 levels by 2020 and increasing the share of non-fossil fuels
in total energy consumption from 7.5% in 2005 to 15% by 2020. The
country’s 12th (2011-2015) Development Programme has set the
target to reduce carbon intensity by 17% within five years, and this
national target has been deconstructed into provincial ones for local
actions. Four emission trading pilots have begun in the cities of Beijing,
Shenzhen and Shanghai and in Guangdong province. Additional
emission trading schemes have been approved for Tianjin and
Chongqing cities as well as Hubei province. As part of the country’s
energy saving programme, the government also requires any operating
entity with annual energy consumption of 10 thousand tonnes of coal
equivalent (7ktoe/a) to have an energy saving target for the next five
years. A number of BP joint venture companies in China will be
required to participate in these initiatives.
For information on the steps that BP is taking in relation to climate
change issues and in relation to GHG regulation and for details of BP’s
GHG reporting see Environment and society on page 45.
Legal proceedings
Proceedings relating to the Deepwater Horizon oil spill
BP’s potential liabilities resulting from threatened, pending and potential
future claims, lawsuits and enforcement actions relating to the 20 April
2010 explosions and fire on the semi-submersible rig Deepwater Horizon
and resulting oil spill (the Incident), together with the potential cost of
implementing remedies sought in the various proceedings, cannot be
fully estimated at this time but they have had and could continue to have
a material adverse impact on the group’s business, competitive position,
financial performance, cash flows, prospects, liquidity, shareholder
returns and/or implementation of its strategic agenda, particularly in the
US. The potential liabilities may continue to have a material adverse
effect on the group’s results and financial condition. See Financial
statements – Note 2 to the financial statements for information regarding
the financial impact of the Incident.
BP p.l.c., BP Exploration & Production Inc. (BPXP) and various other BP
entities (collectively referred to as BP) are among the companies named
as defendants in approximately 2,950 pending civil lawsuits relating to
the Incident and further actions are likely to be brought. BPXP was lease
operator of Mississippi Canyon, Block 252 in the Gulf of Mexico
(Macondo), where the Deepwater Horizon was deployed at the time of
the Incident. The other working interest owners at the time of the
Incident were Anadarko Petroleum Company (Anadarko) and MOEX
Offshore 2007 LLC (MOEX). The Deepwater Horizon, which was owned
and operated by certain affiliates of Transocean Ltd. (Transocean), sank
on 22 April 2010. The pending lawsuits and/or claims arising from the
Incident have generally been brought in US federal and state courts. The
plaintiffs include individuals, corporations, insurers, and governmental
entities and many of the lawsuits purport to be class actions. The
lawsuits assert, among others, claims under the Oil Pollution Act of 1990
(OPA 90), claims for personal injury in connection with the Incident itself
and the response to it, wrongful death, commercial and economic injury,
breach of contract and violations of statutes. Many of the lawsuits assert
claims which are excluded from the Economic and Property Damages
Settlement Agreement (discussed below), including claims for recovery
for losses allegedly resulting from the 2010 federal deepwater drilling
moratoria and/or the related permitting process. The lawsuits seek
various remedies including compensation to injured workers, recovery for
commercial losses and property damage, compensation for personal
injuries and medical monitoring, claims for environmental damage,
remediation costs, claims for unpaid wages, injunctive and declaratory
relief, treble damages and punitive damages. Purported classes of
claimants include residents of the states of Louisiana, Mississippi,
Alabama, Florida and Texas; property owners and rental agents,
fishermen and persons dependent on the fishing industry, charter boat
owners and deck hands, marina owners, gasoline distributors, shipping
interests, restaurant and hotel owners, cruise lines and others who are
property and/or business owners alleged to have suffered economic loss;
and response workers and residents claiming injuries due to exposure to
the components of oil and/or chemical dispersants. Among other claims
arising from the spill response efforts, lawsuits have been filed claiming
that additional payments are due by BP under certain Master Vessel
Charter Agreements entered into in the course of the Vessels of
Opportunity Program implemented as part of the response to the
Incident. Purported class action and individual lawsuits have also been
filed in US state and federal courts, as well as one suit in Canada, against
BP entities and/or various current and former officers and directors
alleging, among other things, shareholder derivative claims, securities
fraud claims, violations of the Employee Retirement Income Security Act
(ERISA) and contractual and quasi-contractual claims related to the
cancellation of the dividend on 16 June 2010.
In August 2010, many of the lawsuits pending in federal court were
consolidated by the Federal Judicial Panel on Multi-district Litigation into
two multi-district litigation proceedings, one in federal district court in
Houston for the securities, derivative and ERISA cases (MDL 2185) and
another in federal district court in New Orleans for the remaining cases
(MDL 2179).
Presentation of evidence in the first trial phase (Phase 1) of a Trial of
Liability, Limitation, Exoneration and Fault Allocation in MDL 2179
concluded on 17 April 2013, and the parties completed post-trial briefing
in respect of Phase 1 on 12 July 2013. The second trial phase (Phase 2),
which addressed source control efforts and the amount of oil that was
spilled into the Gulf as a result of the Incident, completed on 18 October
2013, and post-trial briefing in respect of Phase 2 is substantially
complete. In a further trial phase, which is yet to be scheduled, the
district court will determine the amount of civil penalties arising under the
Clean Water Act based on the court’s rulings as to the presence of
negligence, gross negligence or wilful misconduct in Phases 1 and 2, the
court’s rulings as to quantification of discharge in Phase 2 and the
application of the penalty factors under the Clean Water Act. For further
information, see MDL 2179 and related matters – Trial phases below.
On 3 March 2012, BP announced an agreement in principle with the
Plaintiffs’ Steering Committee (PSC) in MDL 2179 to settle the
substantial majority of legitimate private economic and property damages
claims and exposure-based medical claims stemming from the Incident.
See MDL 2179 and related matters – PSC settlements below.
On 1 June 2010, the US Department of Justice (the DoJ) announced that
it was conducting an investigation into the Incident encompassing
possible violations of US civil or criminal laws, and subsequently created
a unified task force of federal agencies to investigate the Incident. On
15 November 2012, BP announced that it reached agreement with the
US government, subject to court approval, to resolve all federal criminal
charges and all claims by the US Securities and Exchange Commission
(the SEC) against BP arising from the Deepwater Horizon accident, oil
spill and response. See Settlements with the DoJ and SEC below.
MDL 2179 and related matters
DoJ Action; liability limitation-, contribution- and indemnity-related
proceedings; and Trial of Liability, Limitation, Exoneration and Fault
Allocation
On 13 May 2010, Transocean and certain affiliates filed a complaint under
admiralty law in federal court in Texas seeking exoneration from or
limitation of liability as managing owners and operators of the Deepwater
Horizon. That action (the Limitation Action) was consolidated with
MDL 2179 on 24 August 2010.
The United States filed a civil complaint in MDL 2179 against BPXP and
others on 15 December 2010 (the DoJ Action). The complaint seeks a
declaration of liability under OPA 90 and civil penalties under the Clean
Water Act and sets forth a purported reservation of rights on behalf of
the US to amend the complaint or file additional complaints seeking
various remedies under various US federal laws and statutes. See
Financial statements – Note 2.
On 18 February 2011, Transocean filed a third-party complaint against BP,
the US government, and other corporations involved in the Incident,
naming those entities as formal parties in the Limitation Action. On
20 April 2011, Transocean filed claims in the Limitation Action alleging
that BP had breached BP America Production Company’s contract with
Transocean Holdings LLC by BP not agreeing to indemnify Transocean
against liability related to the Incident and by not paying certain invoices.
Transocean also asserted claims against BP under state law, maritime
law, and OPA 90 for contribution.
BP Annual Report and Form 20-F 2013
257
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On 20 April 2011, BP filed claims against Cameron International
Corporation (Cameron), Halliburton Energy Services, Inc. (Halliburton),
and Transocean in the DoJ Action, seeking contribution for any
assessments against BP under OPA 90 based on those entities’ fault. On
20 June 2011, Cameron and Halliburton moved to dismiss BP’s claims
against them in the DoJ Action. BP’s claim against Cameron has been
resolved pursuant to settlement (described below), but Halliburton’s
motion remains pending.
On 20 April 2011, BP asserted claims against Cameron, Halliburton and
Transocean in the Limitation Action. BP’s claims against Transocean
include breach of contract, unseaworthiness of the Deepwater Horizon
vessel, negligence (or gross negligence and/or gross fault as may be
established at trial based upon the evidence), contribution and
subrogation for costs (including those arising from litigation claims)
resulting from the Incident, as well as a declaratory claim that Transocean
is wholly or partly at fault for the Incident and responsible for its
proportionate share of the costs and damages. BP asserted claims
against Halliburton for fraud and fraudulent concealment based on
Halliburton’s misrepresentations to BP concerning, among other things,
the stability testing on the foamed cement used at the Macondo well; for
negligence (or, if established by the evidence at trial, gross negligence)
based on Halliburton’s performance of its professional services, including
cementing and mud logging services; and for contribution and
subrogation for amounts that BP has paid in responding to the Incident,
as well as in OPA 90 assessments and in payments to the plaintiffs. BP
filed a similar complaint against Halliburton in federal court in the
Southern District of Texas, Houston Division, and the action was
transferred to MDL 2179 on 4 May 2011.
On 20 April 2011, Halliburton filed claims in the Limitation Action seeking
indemnification from BP for claims brought against Halliburton in that
action. Halliburton also asserted a claim for negligence, gross negligence
and wilful misconduct against BP and others. On 30 November 2011,
Halliburton filed a motion for summary judgment in MDL 2179. On
21 December 2011, BP filed a cross-motion for partial summary
judgment seeking an order that BP has no contractual obligation to
indemnify Halliburton for fines, penalties or punitive damages resulting
from the Incident. On 31 January 2012, the judge ruled on BP’s and
Halliburton’s indemnity motions, holding that BP is required to indemnify
Halliburton for third-party claims for compensatory damages resulting
from pollution that did not originate from property or equipment of
Halliburton located above the surface of the land or water, regardless of
whether the claims result from Halliburton’s gross negligence. The court,
however, ruled that BP does not owe Halliburton indemnity to the extent
that Halliburton is held liable for punitive damages or for civil penalties
under the Clean Water Act. The court further held that BP’s obligation to
defend Halliburton for third-party claims does not require BP to fund
Halliburton’s defence of third-party claims at this time, nor does it include
Halliburton’s expenses in proving its right to indemnity. The court
deferred ruling on whether BP is required to indemnify Halliburton for any
penalties or fines under the Outer Continental Shelf Lands Act. It also
deferred ruling on whether Halliburton acted so as to invalidate the
indemnity by breaching its contract with BP, by committing fraud, or by
committing another act that materially increased the risk to BP or
prejudiced the rights of BP as an indemnitor.
On 30 May 2011, Transocean filed claims against BP in the DoJ Action
alleging that BP America Production Company had breached its contract
with Transocean Holdings LLC by not agreeing to indemnify Transocean
against liability related to the Incident. Transocean also asserted claims
against BP under state law, maritime law and OPA 90 for contribution.
On 1 November 2011, Transocean filed a motion for partial summary
judgment on certain claims filed in the Limitation Action and the DoJ
Action between BP and Transocean, seeking an order that would bar
BP’s contribution claims against Transocean and require BP to defend
and indemnify Transocean against all pollution claims, including those
resulting from any gross negligence, and from civil fines and penalties
sought by the government. On 7 December 2011, BP filed a cross-
motion for summary judgment seeking an order that BP is not required to
indemnify Transocean for any civil fines and penalties sought by the
government or for punitive damages. On 26 January 2012, the judge
ruled on BP’s and Transocean’s indemnity motions, holding that BP is
required to indemnify Transocean for third-party claims for compensatory
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damages resulting from pollution originating beneath the surface of the
water, regardless of whether the claim results from Transocean’s strict
liability, negligence or gross negligence. The court, however, ruled that
BP does not owe Transocean indemnity for such claims to the extent
Transocean is held liable for punitive damages or for civil penalties under
the Clean Water Act, or if Transocean acted with intentional or wilful
misconduct in excess of gross negligence. The court further held that
BP’s obligation to defend Transocean for third-party claims does not
require BP to fund Transocean’s defence of third-party claims at this
time, nor does it include Transocean’s expenses in proving its right to
indemnity. The court deferred a final ruling on the question of whether
Transocean breached its drilling contract with BP so as to invalidate the
contract’s indemnity clause.
On 8 December 2011, the United States brought a motion for partial
summary judgment in the DoJ Action seeking, among other things, an
order finding that BPXP, Transocean and Anadarko are strictly liable for a
civil penalty under Section 311(b) (7)(A) of the Clean Water Act. On
22 February 2012, the judge ruled on motions filed in the DoJ Action by
the United States, Anadarko, and Transocean seeking early rulings
regarding the liability of BPXP, Anadarko and Transocean under OPA 90
and the Clean Water Act, but limited the order to addressing the
discharge of hydrocarbons occurring under the surface of the water.
Regarding OPA 90, the judge held that BPXP and Anadarko are
responsible parties under OPA 90 with regard to the subsurface
discharge. The judge ruled that BPXP and Anadarko have joint and
several liability under OPA 90 for removal costs and damages for such
discharge, but did not rule on whether such liability under OPA 90 is
unlimited. While the judge held that Transocean is not a responsible party
under OPA 90 for subsurface discharge, the judge left open the question
of whether Transocean may be liable under OPA 90 for removal costs for
such discharge as the owner/operator of the Deepwater Horizon.
Regarding the Clean Water Act, the judge held that the subsurface
discharge was from the Macondo well, rather than from the Deepwater
Horizon, and that BPXP and Anadarko are liable for civil penalties under
Section 311 of the Clean Water Act as owners of the well. Anadarko,
BPXP and the United States each appealed the 22 February 2012 ruling
to the US Court of Appeals for the Fifth Circuit (the Fifth Circuit), and the
appeals were consolidated. Briefing in this appeal is complete and oral
argument was heard on 4 December 2013, but no ruling has been
issued.
On 18 December 2012, Transocean filed a motion seeking an early ruling
that it is not liable in connection with claims for compensatory or punitive
damages, or claims for contribution, brought by private, state, or local
government entities and based on the subsurface discharge of oil.
Transocean’s motion has been fully briefed but remains pending.
On 18 December 2012, Transocean filed a motion seeking an early ruling
that it is not liable in connection with punitive damages claims brought by
members of the Economic and Property Damages Settlement Class (for
a description of the Economic and Property Damages Settlement
Agreement, see below). On 20 December 2012, Transocean filed a
motion seeking an early ruling that it is not liable in connection with BP’s
claims for reimbursement of payments made under the Economic and
Property Damages Settlement Agreement and BP’s separate claims for
spill-related damages, such as lost profits from the Macondo well, which
claims were assigned by BP to the Economic and Property Damages
Settlement Class. On 17 January 2013, Halliburton filed motions seeking
early rulings that it is not liable in connection with punitive damages
claims brought by members of the Economic and Property Damages
Settlement Class; that it is not liable in connection with any contribution
claim for punitive damages, whether asserted by BP or by the Economic
and Property Damages Settlement Class as BP’s assignee; and that it is
not liable in connection with claims assigned by BP to the Economic and
Property Damages Settlement Class. Transocean’s and Halliburton’s
motions have been fully briefed but remain pending.
On 11 January 2013, BP filed a motion in the DoJ Action for partial
summary judgment against the United States, seeking rulings that (1) BP
collected at least 810,000 barrels from the broken riser, from the top of
the blowout preventer and lower marine riser package, and from the
choke and kill lines of the blowout preventer, all before these barrels
reached the waters of the Gulf of Mexico, and (2) that these barrels may
not be counted toward the maximum penalty potentially to be assessed
against BPXP under Section 311 of the Clean Water Act, 33 U.S.C.
§ 1321. BP and the United States subsequently reached a stipulation,
entered by the court on 19 February 2013, providing that 810,000 barrels
of oil were collected without coming into contact with ambient Gulf
waters and that those barrels are not to be used in calculating the
statutory maximum penalty under the Clean Water Act.
On 1 March 2013, Transocean sought the district court’s leave to
supplement its pleadings to include an affirmative defence asserting that
BP’s representations regarding the flow rate at the Macondo well
constituted an intervening and superseding cause of the oil spill for the
majority of its duration. Transocean’s defence claims that BP fraudulently
misrepresented and concealed information regarding the flow rate at the
Macondo well in late April and May 2010, as well as the likelihood of
success of a top-kill approach to stopping the flow of hydrocarbons from
the well, and thus prevented the implementation of alternative means of
source control that Transocean asserts could have capped the well as
early as May 2010. Also on 1 March 2013, Halliburton filed a motion for
leave to amend its answers to assert a similar defence. On 4 March
2013, the court granted Transocean’s motion to file amended answers,
and it granted Halliburton’s motion the following day.
Trial phases
To address certain issues asserted in or relevant to the claims,
counterclaims, cross-claims, third-party claims, and comparative fault
defences raised in the DoJ Action and the Limitation Action, a Trial of
Liability, Limitation, Exoneration and Fault Allocation commenced in
MDL 2179 on 25 February 2013. The presentation of evidence in the first
phase of the trial (Phase 1), which completed on 17 April 2013,
addressed issues arising out of the conduct of various parties allegedly
relevant to the loss of well control at the Macondo well, the ensuing fire
and explosion on the Deepwater Horizon on 20 April 2010, the sinking of
the vessel on 22 April 2010 and the initiation of the release of oil from the
Deepwater Horizon or the Macondo well during those time periods,
including whether BP or any other party was grossly negligent. The
parties completed court-ordered post-trial briefing in respect of Phase 1
on 12 July 2013. On 13 August 2013, BP moved for leave to supplement
the Phase 1 record to include Halliburton’s agreement to plead guilty to
destroying evidence relating to Halliburton’s internal examination of the
Incident and the US government’s press release announcing the
Halliburton plea agreement. The US government, the Plaintiffs’ Steering
Committee and Halliburton have also submitted briefs addressing the
implications of Halliburton’s plea agreement. The district court has yet to
rule on BP’s motion. BP is not currently aware of the timing of the district
court’s ruling in respect of issues addressed in Phase 1 which could be at
any time.
The second trial phase (Phase 2), which commenced on 30 September
2013, addressed (i) ’source control’ issues pertaining to the conduct or
inaction of BP, Transocean or other relevant parties regarding stopping
the release of hydrocarbons stemming from the Incident from 22 April
2010 through to approximately 19 September 2010, and (ii) ’quantification
of discharge’ issues pertaining to the amount of oil actually released into
the Gulf of Mexico as a result of the Incident from the time when these
releases began until the Macondo well was capped on approximately
15 July 2010 and then permanently cemented shut on approximately
19 September 2010. Post-trial briefing in respect of Phase 2 is
substantially complete. On 25 January 2014, Transocean filed a motion to
supplement the Phase 2 record with certain testimony that occurred in a
separate trial of a former BP employee related to the Incident. The district
court has yet to rule on this motion. BP is not currently aware of the
timing of the district court’s ruling in respect of issues addressed in
Phase 2 which could be at any time.
In a further trial phase, which is yet to be scheduled, the district court will
determine the amount of civil penalties arising under the Clean Water Act
based on the court’s rulings as to the presence of negligence, gross
negligence or wilful misconduct in Phases 1 and 2, the court’s rulings as
to quantification of discharge in Phase 2 and the application of the penalty
factors under the Clean Water Act. The district court set a status
conference for 21 March 2014 to address case management issues
relating to this phase of the litigation. The district court also ordered the
parties, on a schedule to be completed prior to 21 March, to serve initial
disclosures and written discovery requests, to provide proposed
stipulations, and to file submissions regarding potential evidence to be
adduced at a penalty phase trial, as well as certain other issues.
The district court in MDL 2179 has wide discretion in its determination as
to whether a defendant’s conduct involved negligence or gross
negligence as well as in its determinations on the volume of oil spilled
and the application of statutory penalty factors.
MOEX, Anadarko and Cameron settlements
BP announced settlement agreements in respect of all claims related to
the Incident with MOEX, Anadarko and Cameron on 20 May 2011,
17 October 2011 and 16 December 2011, respectively. Under the
settlement agreement with MOEX, MOEX paid BP $1.065 billion and also
agreed to transfer all of its 10% interest in the MC252 lease to BP. Under
the settlement agreement with Anadarko, Anadarko paid BP $4 billion
and also agreed to transfer all of its 25% interest in the MC252 lease to
BP. The settlement agreement with Anadarko grants Anadarko the
opportunity for a 12.5% participation in certain future recoveries from
third parties and certain insurance proceeds in the event that such
recoveries and proceeds exceed $1.5 billion in aggregate. Any such
payments to Anadarko are capped at a total of $1 billion. BP agreed to
indemnify MOEX, Anadarko and Cameron for certain claims arising from
the Incident (excluding civil, criminal or administrative fines and penalties,
claims for punitive damages, and certain other claims). The settlement
agreements with MOEX, Anadarko and Cameron are not an admission of
liability by any party regarding the Incident.
PSC settlements
The Economic and Property Damages Settlement resolves certain
economic and property damage claims, and the Medical Benefits Class
Action Settlement resolves certain medical claims by response workers
and certain Gulf Coast residents. The Economic and Property Damages
Settlement includes a $2.3 billion BP commitment to help resolve
economic loss claims related to the Gulf seafood industry (for further
information, see – PSC Settlements – Seafood Compensation Fund below)
and a $57 million fund to support continued advertising that promotes Gulf
Coast tourism. It also resolves property damage in certain areas along the
Gulf Coast, as well as claims for additional payments under certain Master
Vessel Charter Agreements entered into in the course of the Vessels of
Opportunity Program implemented as part of the response to the Incident.
The Economic and Property Damages Settlement does not include claims
made against BP by the DoJ or other federal agencies (including under the
Clean Water Act and for Natural Resource Damages under OPA 90) or by
the states and local governments. Also excluded are certain other claims
against BP, such as securities and shareholder claims pending in MDL
2185, and claims based solely on the deepwater drilling moratorium and/or
the related permitting process.
The Medical Benefits Class Action Settlement involves payments to
qualifying class members based on a matrix for certain Specified Physical
Conditions, as well as a 21-year Periodic Medical Consultation Program
for qualifying class members. Payments of claims under the Medical
Benefits Class Action Settlement could not begin until after the
agreement’s 12 February 2014 Effective Date, being the day after the
resolution of all appeals from the final approval of the Medical Benefits
Class Action Settlement, though class members were permitted to file
claim forms in advance of the Effective Date to facilitate administration of
the Medical Benefits Class Action Settlement upon the Effective Date.
The deadline for submitting claims under the Medical Benefits Class
Action Settlement is one year after the Effective Date. The settlement
also provides that class members claiming Later-Manifested Physical
Conditions may pursue their claims through a mediation/litigation
process, but waive, among other things, the right to seek punitive
damages. Consistent with its commitment to the Gulf, BP has also
agreed as part of the Medical Benefits Class Action Settlement to
provide $105 million to the Gulf Region Health Outreach Program to
improve the availability, scope and quality of healthcare in certain Gulf
Coast communities. This healthcare outreach programme will be
available to, and is intended to benefit, class members and other
individuals in those communities. BP has already begun funding the
projects sponsored by this programme.
Each agreement provides that class members will be compensated for
their claims on a claims-made basis, according to agreed compensation
protocols in separate court-supervised claims processes. The
compensation protocols under the Economic and Property Damages
Settlement provide for the payment of class members’ economic losses
and property damages related to the oil spill. In addition many economic
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and property damages class members will receive payments based on
negotiated risk transfer premiums, which are multiplication factors
designed, in part, to compensate claimants for potential future damages
that are not currently known, relating to the Incident. The Economic and
Property Damages Settlement and the Medical Benefits Class Action
Settlement are not an admission of liability by BP. The settlements are
uncapped except for economic loss claims related to the Gulf seafood
industry under the Economic and Property Damages Settlement and the
$105 million to be provided to the Gulf Region Health Outreach Program
under the Medical Benefits Class Action Settlement.
All class member settlements under the settlement agreements are
payable under the terms of the Trust. Other costs to be paid from the
Trust include state and local government claims, state and local response
costs, natural resource damages and related claims, and final judgments
and settlements. As at 31 December 2013, the aggregate cash balances
in the Trust and the qualified settlement funds amounted to $6.7 billion,
including $1.2 billion remaining in the seafood compensation fund which
has yet to be distributed, and $0.9 billion held for natural resource
damage early restoration. Should the cash balances in the Trust not be
sufficient, payments in respect of legitimate claims and other costs will
be made directly by BP. See Financial statements – Note 2.
The economic and property damages claims process is under court
supervision through the settlement claims process established by the
Economic and Property Damages Settlement. Under the Economic and
Property Damages Settlement, class members release and dismiss their
claims against BP not expressly reserved by that agreement. The
Economic and Property Damages Settlement also provides that, to the
extent permitted by law, BP assigns to the PSC certain of its claims,
rights and recoveries against Transocean and Halliburton for damages
with protections such that Transocean and Halliburton cannot pass those
damages through to BP. Under the Medical Benefits Class Action
Settlement, class members release and dismiss their claims against BP
covered by that settlement, except that class members do not release
claims for Later-Manifested Physical Conditions.
On 24 April 2013, the plaintiffs in two actions arising from the Incident filed
a motion asking the Federal Judicial Panel on Multi-district Litigation to
create new multi-district litigation proceedings for certain claims not
covered by the two class settlements entered into between BP and the
PSC. BP and other defendants opposed the motion and on 9 August 2013
the Federal Judicial Panel on Multi-district Litigation denied the motion.
PSC settlements – appeals
Under US federal law, there is an established procedure for determining
the fairness, reasonableness and adequacy of class action settlements.
Pursuant to this procedure, an extensive notice programme to the public
was implemented to explain the settlement agreements and class
members’ rights, including the right to ’opt out’ of the classes, and the
processes for making claims. The court conducted a fairness hearing on
8 November 2012 in which to consider, among other things, whether to
grant final approval of the Economic and Property Damages Settlement
and the Medical Benefits Class Action Settlement, whether to certify the
classes for settlement purposes only, and the merits of any objections to
the settlement agreements. On 21 November 2012, the parties to the
settlement filed a list of 13,123 individuals and entities who had
submitted timely requests to opt out of the Economic and Property
Damages Settlement Class and 1,638 individuals who had submitted
timely requests to opt out of the Medical Benefits Settlement Class. On
16 November 2012, the court extended the deadline from 5 November
2012 to 15 December 2012 for such excluded persons or entities to
request revocation of their requests to opt out of the settlement. As a
result of such revocations, the number of opt-outs for the Economic and
Property Damages Settlement and the Medical Benefits Class Action
Settlement is fewer than those reported figures.
Following the fairness hearing, the Economic and Property Damages
Settlement was approved by the district court in a final order and
judgment on 21 December 2012, and the Medical Benefits Class Action
Settlement was approved in a final order and judgment on 11 January
2013.
Subsequent to the district court’s final order and judgment approving the
Economic and Property Damages Settlement, groups of purported
members of the Economic and Property Damages Settlement Class (the
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Appellants) appealed from the district court’s approval of that settlement
to the Fifth Circuit. Additionally, a coalition of fishing and community
groups (the Coalition) appealed to the Fifth Circuit from an order of the
district court denying it permission to intervene in the civil action serving
as the vehicle for the Economic and Property Damages Settlement and
further denying it permission to take discovery regarding the fairness of
that settlement. On 11 November 2013, the Fifth Circuit affirmed the
district court’s rulings in respect of the Coalition. On 10 January 2014, a
panel of the Fifth Circuit affirmed the district court’s approval of the
Economic and Property Damages Settlement but left to another panel of
the Fifth Circuit (the business economic loss panel, discussed further
below) the question of how to interpret the Economic and Property
Damages Settlement, including the meaning of the causation
requirements of that agreement. BP and several Appellants have filed
petitions requesting that all the active judges of the Fifth Circuit review
the decision to uphold approval of the settlement.
PSC settlements – Deepwater Horizon Court Supervised Settlement
Program (DHCSSP) and interpretation of the Economic and Property
Damages Settlement Agreement
The DHCSSP, the claims facility operating under the framework
established by the Economic and Property Damages Settlement,
commenced operation on 4 June 2012 under the oversight of Claims
Administrator Patrick Juneau.
As part of its monitoring of payments made by the court-supervised
claims processes operated by the DHCSSP, BP identified multiple
business economic loss claim determinations that appeared to result
from an interpretation of the Economic and Property Damages
Settlement Agreement by that settlement’s claims administrator that BP
believed was incorrect. This interpretation produced a higher number and
value of awards than the interpretation BP used in making its initial
estimate of the total cost of the Economic and Property Damages
Settlement. Pursuant to the mechanisms in the Economic and Property
Damages Settlement Agreement, the claims administrator sought
clarification on this matter from the district court in MDL 2179 and on
5 March 2013, the district court affirmed the claims administrator’s
interpretation of the agreement and rejected BP’s position as it relates to
business economic loss claims (the March Ruling).
BP appealed the district court’s March Ruling and related rulings to the
Fifth Circuit. On 2 October 2013, the business economic loss panel of the
Fifth Circuit (by a 2 to 1 vote) reversed the district court’s denial of BP’s
motion for a preliminary injunction and the district court’s order affirming
the claims administrator’s interpretation of the settlement, remanded the
case for further proceedings and ordered the district court to enter a
’narrowly-tailored’ injunction that suspends payment to claimants
affected by the misinterpretation issue and who do not have ’actual injury
traceable to loss from the Deepwater Horizon accident.’ The business
economic loss panel also retained jurisdiction to review the district
court’s conclusions on remand.
On 18 October 2013, the district court issued a preliminary injunction
that, amongst other things, required the claims administrator to
temporarily suspend payments of business economic loss claims other
than those claims supported by sufficiently matched accrual-basis
accounting or any other business economic loss claim for which the
claims administrator determines that the matching of revenue and
expenses is not an issue. On 25 October 2013, the claims administrator
provided a declaration outlining the criteria that the claims administrator’s
office will use to determine the eligibility of claims for payment. In orders
dated 18 October 2013, 15 November 2013, and 22 November 2013, the
district court held that causation (i.e., whether the claims administrator
could properly pay business economic loss claimants whose injuries are
not traceable to the spill) was not an issue for consideration on remand.
On 21 November 2013, BP filed an emergency motion to enforce the
business economic loss panel’s 2 October 2013 judgment and to enjoin
any further payments to the business economic loss claimants whose
injuries are not traceable to the spill. On 2 December 2013, the business
economic loss panel of the Fifth Circuit granted BP’s motion and ordered
that the issue of causation again be remanded for expeditious
consideration and resolution in crafting “[a] stay tailored so that those
who experienced actual injury traceable to loss from the Deepwater
Horizon accident continue to receive recovery but those who did not do
not receive their payments until this case is fully heard and decided
through the judicial process.” On 5 December 2013, the district court
amended its preliminary injunction related to business economic loss
claims to temporarily suspend the issuance of final determination notices
and payments of business economic loss claims, pending resolution of
the business economic loss issues that are the subject of the pending
remand.
On 24 December 2013, the district court ruled on the issues remanded to
it by the business economic loss panel of the Fifth Circuit, ordering that
the claims administrator, in administering business economic loss claims,
must match revenue with the variable expenses incurred by claimants in
conducting their business, even where the revenues and expenses were
recorded at different times. The district court assigned to the claims
administrator the development of more detailed matching requirements.
On 12 February 2014, the claims administrator issued a draft policy
addressing the matching of revenue and expenses for business
economic loss claims. The parties have made written submissions on the
draft policy and the claims administrator will issue a final policy to which
BP and the PSC have the right to object and seek review by the district
court. As to the issue of causation, the district court ruled that the
Economic and Property Damages Settlement Agreement contained no
causation requirement beyond the revenue and related tests set out in an
exhibit to that agreement, and that BP was judicially estopped from
arguing otherwise. The district court also held that the absence of a
further causation requirement does not defeat class certification nor
invalidate the settlement under the federal class certification rule or
Article III of the US Constitution. On 26 December 2013, BP filed a
motion to consolidate that appeal with the related appeals pending
before the business economic loss panel of the Fifth Circuit. BP
subsequently filed a renewed motion for a permanent injunction that
would prevent the claims administrator from making awards to claimants
whose alleged injuries are not traceable to the spill and a motion to
expedite the court’s resolution of that renewed motion. On 3 March
2014, the business economic loss panel (in a 2 to 1 decision) affirmed the
district court’s ruling on causation and denied BP’s motion for a
permanent injunction. BP is considering its appeal options, including a
potential petition that all the active judges of the Fifth Circuit review the 3
March decision. Under the terms of the business economic loss panel’s
ruling, the injunction temporarily suspending issuance of final
determination notices and payments of business economic loss claims
will be lifted when the matter is transferred back to the district court; the
timing of this would be affected by the status of any such petition by BP.
For more information about BP’s current estimate of the total cost of the
PSC settlements, see Financial Statements – Note 2.
PSC settlements – investigation of the DHCSSP
On 2 July 2013, the district court in MDL 2179 appointed former federal
district court judge Louis Freeh as Special Master to lead an independent
investigation of the DHCSSP in connection with allegations of potential
ethical violations or misconduct within the DHCSSP. On 6 September
2013, Judge Freeh submitted a written report to the district court in
which he presented his findings that the conduct of two attorneys in the
office of the claims administrator may have violated federal criminal
statutes regarding fraud, money laundering, conspiracy or perjury. In an
order issued the same day, the court instructed Judge Freeh to promptly
recommend, design, and test enhanced internal compliance, anti-
corruption, anti-fraud and conflicts of interest policies and procedures,
and assist the claims administrator in the implementation of such policies
and procedures. On 23 September 2013, BP filed a response to Judge
Freeh’s report and requested that the court enter a preliminary injunction
temporarily suspending all payments from the DHCSSP until such time
as improved anti-fraud and other efficiency controls are put in place at the
DHCSSP to the satisfaction of Judge Freeh, the Claims Administrator,
and the court. The court has not yet ruled on BP’s request for a
preliminary injunction. On 17 January 2014, Judge Freeh submitted a
second written report that described the behaviour at the DHCSSP that
led to the resignations of senior staff members.
PSC settlements – Seafood Compensation Fund
On 17 December 2013, BP filed a civil lawsuit in MDL 2179 against
former PSC lawyer Mikal C. Watts, accusing him of having fraudulently
claimed to represent more than 40,000 deckhands who allegedly
suffered economic injuries as a result of the Incident. BP’s action alleges
that BP relied on Mr. Watts’s representations when it agreed to pay
$2.3 billion to the Seafood Compensation Fund (the Fund), which was
established under the Economic and Property Damages Settlement to
compensate those who earn their livelihood from Gulf waters and were
directly affected by the spill, and that the Economic and Property
Damages Class stands to benefit unjustly from the full distribution of the
money remaining in the Fund. In addition, BP filed two motions asking
the district court to suspend further distributions from the Fund and to
determine the extent of the fraud and what portion, if any, of the Fund
should be returned as a result. On 17 January 2014, Mr Watts filed a
motion to stay the litigation pending a parallel criminal investigation and
the PSC also filed a brief opposing BP’s motion seeking an injunction. On
26 February 2014, the district court granted Mr Watts’s motion to stay
the litigation and denied BP’s motion to suspend further distributions, on
the basis that no further payment from the Fund is imminent. The district
court deferred ruling on BP’s motion seeking to determine the extent of
the fraud and what portion, if any, of the seafood fund should be returned
as a result.
State and local civil claims, including under OPA 90
On 12 August 2010, the State of Alabama filed a lawsuit seeking
damages for alleged economic and environmental harms, including
natural resource damages, civil penalties under state law, declaratory and
injunctive relief, and punitive damages as a result of the Incident. On
3 March 2011, the State of Louisiana filed a lawsuit to declare various BP
entities (as well as other entities) liable for removal costs and damages,
including natural resource damages under federal and state law, to
recover civil penalties, attorney’s fees and response costs under state
law, and to recover for alleged negligence, nuisance, trespass, fraudulent
concealment and negligent misrepresentation of material facts regarding
safety procedures and BP’s (and other defendants’) ability to manage the
oil spill, unjust enrichment from economic and other damages to the
State of Louisiana and its citizens, and punitive damages.
On 10 December 2010, the Mississippi Department of Environmental
Quality issued a Complaint and Notice of Violation alleging violations of
several state environmental statutes.
The Louisiana Department of Environmental Quality has issued an
administrative order seeking environmental civil penalties and other relief
under state law. On 23 September 2011, BP removed this matter to
federal district court, and it has been consolidated with MDL 2179.
District Attorneys of 11 parishes in the State of Louisiana have filed suits
under state wildlife statutes seeking penalties for damage to wildlife as a
result of the Incident. On 9 December 2011 and 28 December 2011, the
district court in MDL 2179 granted BP’s motions to dismiss the District
Attorneys’ complaints, holding that those claims are pre-empted by the
Clean Water Act. All 11 of the District Attorneys of parishes in the State
of Louisiana filed notices of appeal. The State of Alabama’s attempt to
intervene in the case was denied. Since May 2012, amicus briefs have
been filed in those appeals by the states of Alabama, Louisiana, and
Mississippi. Oral argument was held on 5 March 2013 and the Fifth
Circuit affirmed the district court’s ruling on 24 February 2014.
On 14 November 2011, the district court in MDL 2179 granted in part
BP’s motion to dismiss the complaints filed by the states of Alabama and
Louisiana. The court’s order dismissed the states’ claims brought under
state law, including claims for civil penalties and the State of Louisiana’s
request for a declaratory judgment under the Louisiana Oil Spill
Prevention and Response Act, holding that those claims were pre-
empted by federal law. It also dismissed the State of Louisiana’s claims
of nuisance and trespass under general maritime law. The court’s order
further held that the states have stated claims for negligence and
products liability under general maritime law, have sufficiently alleged
presentment of their claims under OPA 90 and may seek punitive
damages under general maritime law.
On 9 December 2011, the district court in MDL 2179 granted in part BP’s
motion to dismiss a master complaint brought on behalf of local
government entities. The court’s order dismissed the plaintiffs’ state law
claims and limited the types of maritime law claims the plaintiffs may
pursue, but also held that the plaintiffs have sufficiently alleged
presentment of their claims under OPA 90 and that certain local
government entity claimants may seek punitive damages under general
maritime law. The court did not, however, lift an earlier stay on the
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underlying individual complaints raising those claims or otherwise apply
his dismissal of the master complaint to those individual complaints.
In January 2013, the states of Alabama, Mississippi and Florida
submitted or asserted claims to BP under OPA 90 for alleged losses
including economic losses and property damage as a result of the
Incident. BP is evaluating these claims. The states of Louisiana and Texas
have also asserted similar claims. The amounts claimed, certain of which
include punitive damages or other multipliers, are very substantial.
However, BP considers these claims unsubstantiated and the
methodologies used to calculate these claims to be seriously flawed, not
supported by OPA 90, not supported by documentation, and to
substantially overstate the claims. Similar claims have also been
submitted by various local government entities and a foreign
government. These claims under OPA 90 are substantial in aggregate,
and more claims are expected to be submitted. The amounts alleged in
the submissions for state and local government claims total
approximately $35 billion. BP will defend vigorously against these claims
if adjudicated at trial. Certain of these states (including the states of
Alabama, Florida, Texas and Mississippi, as described below) and local
government entities have filed civil lawsuits that pertain to claims
asserted by them under their earlier OPA 90 submissions to BP.
In April 2013, the states of Alabama, Florida, and Mississippi each filed
new actions against BP related to the Incident, which have been
consolidated with MDL 2179. On 19 April 2013, the State of Alabama
filed a new action against BP alleging general maritime law claims of
negligence, gross negligence, and wilful misconduct; claims under OPA
90 seeking damages for removal costs, natural resource damages,
property damage, lost tax and other revenue, and damages for providing
increased public services during or after removal activities; and various
state law claims. The State of Alabama’s complaint also seeks punitive
damages.
On 20 April 2013, the State of Florida filed suit against BP and Halliburton
in federal court in Florida, and its case has also been transferred to MDL
2179. Florida’s complaint alleges general maritime law claims for
negligence and gross negligence; OPA 90 claims for alleged lost tax
revenue and other economic damages; and various state law claims.
Florida also seeks punitive damages.
The State of Mississippi filed both federal court and state court
complaints in Mississippi against BP in April 2013. Mississippi’s federal
court complaint alleges OPA 90 claims against BP, Transocean, and
Anadarko for natural resource damages, property damage, lost tax
revenue, and damages for providing increased public services during or
after removal activities. It asserts general maritime law claims for
negligence and gross negligence against Halliburton only. Mississippi’s
state court complaint alleges various state law claims, including
negligence, gross negligence, and willful misconduct. Both Mississippi
complaints seek punitive damages. The State of Mississippi’s federal
court action and state court action have both been consolidated with
MDL 2179.
On 17 May 2013, the State of Texas filed suit against BP and others in
federal court in Texas. Its complaint asserts claims under OPA 90 for
natural resource damages and lost sales tax and state park revenue;
claims for natural resource damages under the Comprehensive
Environmental Response, Compensation, and Liability Act (CERCLA); and
claims for natural resource damages, cost recovery, civil penalties, and
economic damages under state environmental statutes. The State of
Texas’s action has been consolidated with MDL 2179.
On 14 January 2014, the district court in MDL 2179 set a briefing
schedule, to be completed by 28 March 2014, for BP’s motion to strike
the State of Alabama’s jury trial demand as to its claim for compensatory
damages under OPA 90 which BP then filed on 14 February 2014.
On 5 March 2014, the State of Florida filed a lawsuit to declare various
BP entities (and other entities) liable for removal costs and natural
resource damages.
Agreement for early natural resource restoration
On 21 April 2011, BP announced an agreement with natural resource
trustees for the US and five Gulf Coast states, providing for up to
$1 billion to be spent on early restoration projects to address natural
resource injuries resulting from the Incident. Funding for these projects
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will come from the $20-billion trust fund. As of December 2013, BP and
the trustees had reached agreement, or agreement in principle, on a
total of 54 early restoration projects that are expected to cost
approximately $698 million. These include 10 projects that are already in
place or under way, and 44 projects that are subject to a further
regulatory review and public comment process and further trustee
approval before they may proceed.
Other civil complaints
On 26 August 2011, the district court in MDL 2179 granted in part BP’s
motion to dismiss a master complaint raising claims for economic loss by
private plaintiffs, dismissing the plaintiffs’ state law claims and limiting
the types of maritime law claims the plaintiffs may pursue, but also held
that certain classes of claimants may seek punitive damages under
general maritime law. The court did not, however, lift an earlier stay on
the underlying individual complaints raising those claims or otherwise
apply its dismissal of the master complaint to those individual complaints.
On 30 September 2011, the court granted in part BP’s motion to dismiss
a master complaint asserting personal injury claims on behalf of persons
exposed to crude oil or chemical dispersants, dismissing the plaintiffs’
state law claims, claims by seamen for punitive damages, claims for
medical monitoring damages by asymptomatic plaintiffs, claims for
battery and nuisance under maritime law, and claims alleging negligence
per se. As with its other rulings on motions to dismiss master
complaints, the court did not lift an earlier stay on the underlying
individual complaints raising those claims or otherwise apply its dismissal
of the master complaint to those individual complaints.
Citizens groups have also filed either lawsuits or notices of intent to file
lawsuits seeking civil penalties and injunctive relief under the Clean
Water Act and other environmental statutes. On 16 June 2011, the
district court in MDL 2179 granted BP’s motion to dismiss a master
complaint raising claims for injunctive relief under various federal
environmental statutes brought by various citizens groups and others.
The court did not, however, lift an earlier stay on the underlying individual
complaints raising those claims for injunctive relief or otherwise apply its
dismissal of the master complaint to those individual complaints. In
addition, a different set of environmental groups filed a motion to
reconsider dismissal of their Endangered Species Act claims on 14 July
2011. That motion remains pending.
On 31 January 2012, the district court in MDL 2179, on motion by the
Center for Biological Diversity, entered final judgment on the basis of the
16 June 2011 order with respect to two actions brought against BP by
that plaintiff. On 2 February 2012, the Center for Biological Diversity filed
a notice of appeal of both actions to the Fifth Circuit. Following oral
argument, the Fifth Circuit ruled in BP’s favour on 9 January 2013 in
virtually all respects, though it remanded the Center for Biological
Diversity’s claim under the Emergency Planning and Community Right to
Know Act (EPCRA) to the district court. On 22 January 2013, the Center
for Biological Diversity filed a Petition for Panel Rehearing in the Fifth
Circuit, which was denied on 4 February 2013. In January 2014, the
district court in MDL 2179 set a schedule for proceedings on remand of
the EPCRA claim under which limited discovery is under way, after which
the parties may file cross-motions for summary judgment to be fully
briefed by 19 May 2014.
On 11 July 2012, BP filed motions to dismiss several categories of claims
in MDL 2179 that were not covered by the Economic and Property
Damages Settlement. On 1 October 2012, the court granted BP’s
motion, dismissing (1) claims alleging a reduction in the value of real
property caused by the oil spill or other contaminant where the property
was not physically touched by the oil and the property was not sold;
(2) claims by or on behalf of entities marketing BP-branded fuels that they
have suffered damages, including loss of business, income, and profits,
as a result of the loss of value to the ‘BP’ brand or name; and (3) claims
by or on behalf of recreational fishermen, recreational divers, beachgoers,
recreational boaters, and similar claimants, that they have suffered
damages that include loss of enjoyment of life from the inability to use of
the Gulf of Mexico for recreation and amusement purposes. The judge
did not, however, lift an earlier stay on the underlying individual
complaints raising those claims or otherwise apply his dismissal of those
categories of claims to those individual complaints. This order was
appealed to the Fifth Circuit, but the appeal was ultimately dismissed on
14 May 2013 for lack of jurisdiction.
Halliburton lawsuits
On 19 April 2011, Halliburton filed a lawsuit in Texas state court seeking
indemnification from BPXP for certain tort and pollution-related liabilities
resulting from the Incident. On 3 May 2011, BPXP removed Halliburton’s
case to federal court, and on 9 August 2011, the action was transferred
to MDL 2179.
indemnity in the drilling contract between BP and Transocean. On
29 August 2013, the Fifth Circuit withdrew its 1 March 2013 opinion and
certified two questions of Texas law at issue in the appeal to the
Supreme Court of Texas. The Supreme Court of Texas accepted the
certification. Briefing is expected to be completed on 10 March 2014, and
oral argument has not yet been scheduled.
On 1 September 2011, Halliburton filed an additional lawsuit against BP
in Texas state court alleging that BP did not identify the existence of a
purported hydrocarbon zone at the Macondo well to Halliburton in
connection with Halliburton’s cement work performed before the
Incident and that BP has concealed the existence of this purported
hydrocarbon zone following the Incident. Halliburton claims that the
alleged failure to identify this information has harmed its business
ventures and reputation and resulted in lost profits and other damages.
On 7 February 2012, the lawsuit was transferred to MDL 2179.
RICO lawsuits
BP has been named in several lawsuits alleging claims under the
Racketeer-Influenced and Corrupt Organizations Act (RICO). On 15 July
2011, the district court granted BP’s motion to dismiss a master
complaint raising RICO claims against BP. The court’s order dismissed
the claims of the plaintiffs in four RICO cases encompassed by the
master complaint.
Non-US government lawsuits
On 15 September 2010, three Mexican states bordering the Gulf of
Mexico (Veracruz, Quintana Roo, and Tamaulipas) filed lawsuits in federal
court in Texas against several BP entities. These lawsuits were
subsequently transferred to MDL 2179 on 4 November 2010. These
lawsuits allege that the Incident harmed their tourism, fishing, and
commercial shipping industries (resulting in, among other things,
diminished tax revenue), damaged natural resources and the
environment, and caused the states to incur expenses in preparing a
response to the Incident. On 9 December 2011, the district court in MDL
2179 granted in part BP’s motion to dismiss the three Mexican states’
complaints, dismissing their claims under OPA 90 and for nuisance and
negligence per se, and preserving their claims for negligence and gross
negligence only to the extent there has been a physical injury to a
proprietary interest of the states. BP, other defendants and the three
Mexican states filed cross-motions for summary judgment on 4 January
2013 on the issue of whether the Mexican states have a proprietary
interest in the matters asserted in their complaints. The district court
heard oral argument on the cross-motions on 27 June 2013, and on
6 September 2013 the court granted defendants’ motions. On
12 September 2013, the court issued a final judgment dismissing the
three Mexican states’ claims with prejudice. On 4 October 2013, the
three Mexican states filed notices of appeal from the judgment to the
Fifth Circuit. The Mexican states’ opening brief in the appeal is due on
31 March 2014.
On 5 April 2011, the State of Yucatan submitted a claim to the Gulf Coast
Claims Facility (GCCF) alleging potential damage to its natural resources
and environment, and seeking to recover the cost of assessing the
alleged damage. On 18 September 2013, the State of Yucatan filed suit
against BP in federal court in Florida, and, on 13 December 2013, its
action was transferred to MDL 2179.
On 19 April 2013, the Mexican federal government filed a civil action
against BP and others in MDL 2179. The complaint seeks a
determination that each defendant bears liability under OPA 90 for
damages that include the costs of responding to the spill; natural
resource damages allegedly recoverable by Mexico as an OPA 90
trustee; and the net loss of taxes, royalties, fees, or net profits.
Insurance-related matters
On 1 March 2012, the district court in MDL 2179 issued a partial final
judgment dismissing with prejudice certain claims by BP, Anadarko and
MOEX for additional insured coverage under insurance policies issued to
Transocean for the sub-surface pollution liabilities BP, Anadarko and
MOEX have incurred and will incur with respect to the Macondo well oil
release. BP filed a notice of appeal from the district court’s judgment to
the Fifth Circuit and on 1 March 2013, the Fifth Circuit reversed the
district court’s judgment, rejecting the district court’s ruling that the
insurance that BP is entitled to receive as an additional insured under the
Transocean insurance policies at issue is limited to the scope of the
False Claims Act actions
BP is aware that actions have been or may be brought under the Qui Tam
(whistle-blower) provisions of the False Claims Act (FCA). On
17 December 2012, the court ordered unsealed one complaint that had
been filed in the US District Court for the Eastern District of Louisiana by
an individual under the FCA’s Qui Tam provisions. The complaint alleged
that BP and another defendant had made false reports and certifications
of the amount of oil released into the Gulf of Mexico following the
Incident. On 17 December 2012, the DoJ filed with the court a notice
that the DoJ elected to decline to intervene in the action. On 31 January
2013, the complaint was transferred to MDL 2179 and remains stayed.
MDL 2185 and other securities-related litigation
Since the Incident, shareholders have sued BP and various of its current
and former officers and directors asserting shareholder derivative claims
and class and individual claims. Many of these lawsuits have been
consolidated or co-ordinated in federal district court in Houston
(MDL 2185).
Shareholder derivative litigation
Shareholder derivative lawsuits related to the Incident have been filed in
US federal and state courts against various current and former officers
and directors of BP alleging, among other things, breach of fiduciary duty,
gross mismanagement, abuse of control and waste of corporate assets.
On 15 September 2011, the district court in MDL 2185 granted BP’s
motion to dismiss the pending consolidated shareholder derivative
litigation on the grounds that the courts of England are the appropriate
forum for the litigation. On 8 December 2011, a final judgment was
entered dismissing the shareholder derivative case and, on 3 January
2012, one of the derivative plaintiffs filed a notice of appeal to the Fifth
Circuit. On 16 January 2013, the Fifth Circuit affirmed dismissal of the
action. All of the state court derivative actions have been dismissed
based on the final outcome of the federal case.
Securities class action
On 13 February 2012, the district court in MDL 2185 issued two
decisions on the defendants’ motions to dismiss the two consolidated
securities fraud complaints filed on behalf of purported classes of BP
ordinary shareholders and ADS holders. The court dismissed all of the
claims of the ordinary shareholders, dismissed the claims of the lead
class of ADS holders against most of the individual defendants while
holding that a subset of the claims against two individual defendants and
the corporate defendants could proceed, and dismissed all of the claims
of a smaller purported subclass with leave to re-plead in 20 days. On
2 April 2012, the plaintiffs in the lead class and subclass filed an amended
consolidated complaint with claims based on (1) the 12 alleged
misstatements that the court held were actionable in its February 2012
order on BP’s motion to dismiss the earlier complaints; and (2) 13 alleged
misstatements concerning BP’s operating management system that the
judge either rejected with leave to re-plead or did not address in his
February decisions. On 2 May 2012, defendants moved to dismiss the
claims based on the 13 statements in the amended complaint that the
judge did not already rule are actionable. On 6 February 2013, the court
granted in part this motion to dismiss, rejecting the plaintiffs’ claims
based on 10 of the 17 statements at issue in the motion and also
dismissing all claims against former BP employee Andrew Inglis. On
6 December 2013, the court denied the plaintiffs’ motion for class
certification and gave the plaintiffs 30 days to renew that motion, and the
plaintiffs renewed their motion on 6 January 2014. Briefing on the
plaintiffs’ renewed motion is scheduled to complete on 10 March 2014
and a hearing on this motion is scheduled for 21 April 2014. On
20 December 2013, the court revised the schedule for the action and set
a trial date for 14 October 2014.
Individual securities litigation
In April and May 2012, six cases (three of which were consolidated into
one action) were filed in state and federal courts by one or more state,
county or municipal pension funds against BP entities and several current
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and former officers and directors seeking damages for alleged losses
those funds suffered because of their purchases of BP ordinary shares
and, in two cases, ADSs. The funds assert various state law and federal
law claims. From July 2012 to November 2013, 14 additional cases were
filed in Texas state and federal courts (later consolidated into 11 actions)
by pension or investment funds or advisers against BP entities and
current and former officers and directors, asserting state law and other
claims and seeking damages for alleged losses that those funds suffered
because of their purchases of BP ordinary shares and/or ADSs, and one
case was filed in New York federal court by funds that purchased BP
ordinary shares and ADSs, asserting state and federal law claims. All of
the cases have been transferred to federal court in Houston and, with the
exception of one case that has been stayed, the judge presiding over
MDL 2185. One case was voluntarily dismissed on 9 May 2013. On
3 October 2013, the judge granted in part and denied in part the
defendants’ motion to dismiss three of the remaining 14 cases. A subset
of the claims was dismissed. The judge held that English law governs the
plaintiffs’ remaining claims (with the exception of the federal law claims
based on purchases of ADSs and a potential claim under Ohio state law
against BP p.l.c. by certain Ohio funds). On 11 December 2013,
defendants moved to dismiss 10 of the remaining cases and answered
the complaints in two others. On 5 December 2013, the Ohio funds filed
an amended complaint withdrawing their English law claim and asserting
only a claim under Ohio state law. On 6 January 2014, BP moved to
dismiss that case.
Canadian class action
On 20 July 2012, a BP entity received an amended statement of claim for
an action in Alberta, Canada, filed by three plaintiffs seeking to assert
claims under Canadian law against BP on behalf of a class of Canadian
residents who allegedly suffered losses because of their purchase of BP
ordinary shares and ADSs. This case was dismissed on jurisdictional
grounds on 14 November 2012. On 15 November 2012, one of the
plaintiffs re-filed a statement of claim against BP in Ontario, Canada,
seeking to assert the same claims under Canadian law against BP on
behalf of a class of Canadian residents. BP moved to dismiss that action
for lack of jurisdiction, and on 9 October 2013 the Ontario court denied
BP’s motion. On 7 November 2013, BP filed a notice of appeal from that
decision, and filed its papers on that appeal on 19 December 2013;
argument is scheduled for 24 June 2014.
Dividend-related proceedings
On 5 July 2012, the district court in MDL 2185 issued a decision granting
BP’s motion to dismiss, for lack of personal jurisdiction, the lawsuit
against BP p.l.c. for cancelling its dividend payment in June 2010. On
10 August 2012, the plaintiffs filed an amended complaint, which BP
moved to dismiss on 9 October 2012. On 12 April 2013, the court
granted BP’s motion and dismissed the lawsuit for lack of personal
jurisdiction and on the alternative grounds of failure to state a claim and
that the courts of England are the more appropriate forum for the
litigation. On 16 June 2013, the court granted the plaintiff’s motion to
amend its decision so as to eliminate the alternative grounds for
dismissal. On 22 November 2013, the plaintiffs filed a new and
substantially identical action against BP p.l.c. in federal court in New York,
which was transferred to the judge presiding over MDL 2185. BP p.l.c.
moved to dismiss that new action on 19 February 2014.
ERISA
On 30 March 2012, the district court in MDL 2185 issued a decision
granting the defendants’ motions to dismiss the ERISA case related to
BP share funds in several employee benefit savings plans. On 11 April
2012, the plaintiffs requested leave to file an amended complaint, which
was denied on 27 August 2012. Final judgment dismissing the case was
entered on 4 September 2012 and, on 25 September 2012, the plaintiffs
filed a notice of appeal to the Fifth Circuit. That appeal was fully briefed
as of 21 June 2013 and oral argument was held on 4 November 2013,
but no ruling has yet been issued.
Settlements with the DoJ and SEC
On 1 June 2010, the DoJ announced that it was conducting an
investigation into the Incident encompassing possible violations of
US civil or criminal laws, and subsequently created a unified task force of
federal agencies to investigate the Incident. On 15 November 2012, BP
announced that it reached agreement with the US government, subject
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to court approval, to resolve all federal criminal charges and all claims by
the SEC against BP arising from the Deepwater Horizon accident, oil spill
and response.
On 29 January 2013, the US District Court for the Eastern District of
Louisiana accepted BP’s pleas regarding the federal criminal charges, and
BP was sentenced in connection with the criminal plea agreement. BP
pleaded guilty to 11 felony counts of Misconduct or Neglect of Ships
Officers relating to the loss of 11 lives; one misdemeanour count under
the Clean Water Act; one misdemeanour count under the Migratory Bird
Treaty Act; and one felony count of obstruction of Congress.
Pursuant to that sentence, BP will pay $4 billion, including $1,256 million
in criminal fines, in instalments over a period of five years. Under the
terms of the criminal plea agreement, a total of $2,394 million will be paid
to the National Fish & Wildlife Foundation (NFWF) over a period of five
years. In addition, $350 million will be paid to the National Academy of
Sciences (NAS) over a period of five years. BP made its required
payments that were due by 30 March and 29 April 2013 and 29 January
2014, totalling $926 million. The next scheduled payments under the plea
agreement total $595 million and are due by 29 January 2015.
The court also ordered, as previously agreed with the US government,
that BP serve a term of five years’ probation. Pursuant to the terms of
the plea agreement, the court also ordered certain equitable relief,
including additional actions, enforceable by the court, to further enhance
the safety of drilling operations in the Gulf of Mexico. These
requirements relate to BP’s risk management processes, such as third-
party auditing and verification, BP’s oil spill response plan, training, and
well control equipment and processes such as blowout preventers and
cementing. BP has also agreed to maintain a real-time drilling operations
monitoring centre in Houston or another appropriate location. In addition,
BP will undertake several initiatives with academia and regulators to
develop new technologies related to deepwater drilling safety. The
resolution also provides for the appointment of two monitors, both with
terms of up to four years. A process safety monitor will review, and
provide recommendations concerning BPXP’s process safety and risk
management procedures for deepwater drilling in the Gulf of Mexico. An
ethics monitor will review and provide recommendations concerning
BP’s ethics and compliance programme. BP has also agreed to retain an
independent third-party auditor who will review and report to the
probation officer, the DoJ and BP regarding BPXP’s compliance with the
key terms of the plea agreement including the completion of safety and
environmental management systems audits, operational oversight
enhancements, oil spill response training and drills and the
implementation of best practices. Under the plea agreement, BP has also
agreed to co-operate in ongoing criminal actions and investigations,
including prosecutions of four former employees who have been
separately charged.
In its resolution with the SEC, BP has resolved the SEC’s Deepwater
Horizon-related claims against the company under Sections 10(b) and
13(a) of the Securities Exchange Act of 1934 and the associated rules. BP
has agreed to a civil penalty of $525 million, payable in three instalments
over a period of three years, and has consented to the entry of an
injunction prohibiting it from violating certain US securities laws and
regulations. The SEC’s claims are premised on oil flow rate estimates
contained in three reports provided by BP to the SEC during a one-week
period (on 29 and 30 April 2010 and 4 May 2010), within the first 14 days
after the accident. BP’s consent was incorporated in a final judgment and
court order on 10 December 2012, and BP made its first payment of
$175 million on 11 December 2012 and its second payment of
$175 million on 1 August 2013. The final instalment of $175 million, plus
accrued interest, is due on 1 August 2014.
BP’s November 2012 agreement with the US government does not
resolve the DoJ’s civil claims, such as claims for civil penalties under the
Clean Water Act or claims for natural resource damages under OPA 90.
Neither does it resolve the private securities claims pending in
MDL 2185.
US Environmental Protection Agency matters
On 28 November 2012, the US Environmental Protection Agency (EPA)
notified BP that it had temporarily suspended BP p.l.c., BPXP and a
number of other BP subsidiaries from participating in new federal
contracts. As a result of the temporary suspension, the BP entities listed
in the notice are ineligible to receive any US government contracts either
through the award of a new contract, or the extension of the term of or
renewal of an expiring contract. The suspension does not affect existing
contracts the company has with the US government, including those
relating to current and ongoing drilling and production operations in the
Gulf of Mexico.
The charges to which BPXP pleaded guilty included one misdemeanour
count under the Clean Water Act that, by operation of law following the
court’s acceptance of BPXP’s plea, triggers a statutory debarment, also
referred to as mandatory debarment, of the facility where the Clean
Water Act violation occurred. On 1 February 2013, the EPA issued a
notice that BPXP was mandatorily debarred at its Houston headquarters.
Mandatory debarment prevents a company from entering into new
contracts or new leases with the US government that would be
performed at the facility where the Clean Water Act violation occurred. A
mandatory debarment does not affect any existing contracts or leases a
company has with the US government and will remain in place until such
time as the debarment is lifted through an agreement with the EPA or
the EPA decides to lift the debarment.
On 15 February 2013, BP filed an administrative challenge with the EPA
seeking to lift the 28 November 2012 suspension of 22 BP entities and
the 1 February 2013 mandatory debarment of BPXP at its Houston
headquarters. On 19 July 2013, the EPA affirmed its suspension and
mandatory debarment decisions. BP maintains that the EPA’s actions do
not have an adequate legal basis and do not reflect BP’s present status
as a responsible government contractor. On 12 August 2013, BP filed a
lawsuit in the US District Court for the Southern District of Texas (the
Texas District Court) challenging the EPA’s suspension and mandatory
debarment decisions. On 25 November 2013, BP filed a motion for
summary judgment on its claims in the Texas District Court. The UK
government and a coalition of major trade and business groups led by the
American Petroleum Institute later filed friend of the court (amicus) briefs
supporting BP’s position. On 28 January 2014, the EPA filed a motion for
summary judgment in the Texas District Court. Both motions remain
pending with briefing scheduled to be completed by 14 March 2014.
On 26 November 2013, the EPA issued a Notice of Continued
Suspensions and Proposed Debarments that continued the suspensions
of the previously suspended BP entities, suspended two new BP entities
(BP Alternative Energy and BP Pipelines (Alaska) Inc.), and proposed
discretionary debarment of all suspended BP entities.
for a Coastal Use Permit to remove certain ’orphan’ anchors that had
been placed in coastal waters to secure containment boom during oil spill
response operations in 2010. On 6 September 2013, BP sent a letter to
the LDNR observing that the Order is pre-empted by federal law and
would require the consent of the Federal On-Scene Coordinator following
a net environmental benefits analysis. BP has requested that the LDNR
withdraw the Order or initiate a judicial hearing. The LDNR has yet to
withdraw the Order or initiate a judicial hearing, but responded on
17 September 2013 that the Order will not take effect unless and until
the LDNR assesses costs or penalties or files a lawsuit. On
18 September 2013, BP filed a complaint in the US District Court for the
Middle District of Louisiana seeking to enjoin the State of Louisiana from
enforcing the Order on grounds of federal pre-emption. The LDNR moved
to dismiss BP’s complaint on 5 November 2013, and BP filed a motion
for summary judgment on 18 December 2013. Briefing on the motions is
now complete.
Non-US lawsuits
Mexico
On 18 October 2012, before a Mexican Federal District Court located in
Mexico City, a class action complaint was filed against BPXP, BP America
Production Company, and other BP subsidiaries. The plaintiffs, consisting
of fishermen and other groups, are seeking, among other things,
compensatory damages for the class members who allegedly suffered
economic losses, as well as an order requiring BP to remediate
environmental damage resulting from the Incident, to provide funding for
the preservation of the environment and to conduct environmental
impact studies in the Gulf of Mexico for the next 10 years. The plaintiffs
did not properly serve the BP entities named as defendants and, on
20 January 2014, the plaintiffs voluntarily dismissed their action.
Ecuador
A claim was commenced against BP by a group of claimants on 26 July
2012 in Ecuador. The majority of the claimants represent local NGOs. The
claim alleges that through the Incident and BP’s response to it, BP
violated the ’rights of nature’. The claim is not monetary but rather seeks
injunctive relief. Two previous claims on identical grounds were
dismissed at an early stage by the Ecuadorian courts. On 3 December
2012, the Ecuadorian court of first instance dismissed the claim. On
7 December 2012, the claimants filed a timely notice of appeal to the
Ecuadorian court of second instance. On 28 February 2013, the court
affirmed the dismissal by the lower court.
BP continues to work with the EPA in preparing an administrative
agreement to resolve these suspension and debarment issues.
Pending investigations and reports relating to the Deepwater
Horizon oil spill
US Department of Interior matters
On 14 September 2011, the US Coast Guard and Bureau of Ocean
Energy Management, Regulation and Enforcement (BOEMRE) issued a
report regarding the causes of the 20 April 2010 Macondo well blowout
(the BOEMRE Report). The BOEMRE Report states that decisions by BP,
Halliburton and Transocean increased the risk or failed to fully consider or
mitigate the risk of a blowout on 20 April 2010. The BOEMRE Report also
states that BP, Transocean and Halliburton violated certain regulations
related to offshore drilling. In itself, the BOEMRE Report does not
constitute the initiation of enforcement proceedings relating to any
violation. On 12 October 2011, the US Department of the Interior Bureau
of Safety and Environmental Enforcement issued to BPXP, Transocean,
and Halliburton Notification of Incidents of Noncompliance (INCs). The
notification issued to BPXP is for a number of alleged regulatory
violations concerning Macondo well operations. The Department of
Interior has indicated that this list of violations may be supplemented as
additional evidence is reviewed, and on 7 December 2011, the Bureau of
Safety and Environmental Enforcement issued to BPXP a second INC.
This notification was issued to BP for five alleged violations related to
drilling and abandonment operations at the Macondo well. BP has filed an
administrative appeal with respect to the first and second INCs. BP has
filed a joint stay of proceedings with the Department of Interior with
respect to both INCs.
Louisiana Department of Natural Resources
On 21 August 2013, the Louisiana Department of Natural Resources
(LDNR) issued a Cease and Desist Order (the Order) directing BP to apply
CSB investigation
The US Chemical Safety and Hazard Investigation Board (CSB) is
conducting an investigation of the Incident that is focused on the
explosions and fire, and not the resulting oil spill or response efforts. As
part of this effort, on 24 July 2012, the CSB conducted a hearing at which
it released its preliminary findings on, among other things, the use of
safety indicators by industry (including BP and Transocean) and
government regulators in offshore operations prior to the Incident. On
30 March 2013, a ruling was issued in the CSB’s pending enforcement
action against Transocean in federal district court in the Southern District
of Texas holding that the CSB has jurisdiction to investigate the Incident
and its subpoenas are valid and enforceable. On 3 May 2013, Transocean
appealed to the Fifth Circuit, the district court’s ruling that the CSB has
jurisdiction. That appeal is currently pending. On 20 June 2013, the CSB
sent BP a letter stating that BP must comply with the outstanding
document subpoenas. BP is producing documents in compliance with
the CSB’s document subpoenas. Separately the CSB has announced that
it may issue its reports in this matter in 2014. The CSB may seek to
recommend improvements to BP and industry practices and to regulatory
programmes to prevent recurrence and mitigate potential consequences.
National Academy of Engineering/National Research Council report
A Committee of the National Academy of Engineering/National Research
Council that had been reviewing methods for assessing impacts on
natural resources issued its final report on 10 July 2013. The report
endorses use of an ‘ecosystems services approach,’ and discusses
additional data, models, research, and analysis that potentially would be
needed in order to apply the approach to the Deepwater Horizon oil spill.
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Other legal proceedings
FERC and CFTC matters
The US Federal Energy Regulatory Commission (FERC) and the
US Commodity Futures Trading Commission (CFTC) have been
investigating several BP entities regarding trading in the next-day natural
gas market at Houston Ship Channel during September, October and
November 2008. The FERC Office of Enforcement staff notified BP on
12 November 2010 of their preliminary conclusions relating to alleged
market manipulation in violation of 18 C.F.R. Sec. 1c.1. On 30 November
2010, CFTC Enforcement staff also provided BP with a notice of intent to
recommend charges based on the same conduct alleging that BP
engaged in attempted market manipulation in violation of Section 6(c),
6(d), and 9(a)(2) of the Commodity Exchange Act. On 23 December 2010,
BP submitted responses to the FERC and CFTC November 2010 notices
providing a detailed response that it did not engage in any inappropriate
or unlawful activity. On 28 July 2011, FERC staff issued a Notice of
Alleged Violations stating that it had preliminarily determined that several
BP entities fraudulently traded physical natural gas in the Houston Ship
Channel and Katy markets and trading points to increase the value of
their financial swing spread positions. On 5 August 2013, the FERC
issued an Order to Show Cause and Notice of Proposed Penalty directing
BP to respond to a FERC Enforcement Staff report, which FERC issued
on the same day, alleging that BP manipulated the next-day, fixed price
gas market at Houston Ship Channel from mid-September 2008 to
30 November 2008. The FERC Enforcement Staff report proposes a civil
penalty of $28 million and the surrender of $800,000 of alleged profits.
BP filed its answer on 4 October 2013 denying the allegations and
moving for dismissal.
CSB matters
On 23 March 2005, an explosion and fire occurred at the Texas City
refinery. Fifteen workers died in the incident and many others were
injured. BP Products North America, Inc. (BP Products) has resolved all
civil injury claims and all civil and criminal governmental claims arising
from the March 2005 incident. In March 2007, the US Chemical Safety
and Hazard Investigation Board (CSB) issued a report on the incident. The
report contained recommendations to the Texas City refinery and to the
board of directors of BP. To date, the CSB has accepted that the majority
of BP’s responses to its recommendations have been satisfactorily
addressed. BP and the CSB are continuing to discuss the remaining open
recommendations with the objective of the CSB agreeing to accept these
as satisfactorily addressed as well.
OSHA matters
On 29 October 2009, the US Occupational Safety and Health
Administration (OSHA) issued citations to the Texas City refinery related
to the Process Safety Management (PSM) Standard. On 12 July 2012,
OSHA and BP resolved 409 of the 439 citations. The agreement required
that BP pay a civil penalty of $13,027,000 and that BP abate the alleged
violations by 31 December 2012. BP completed these requirements and
the agreement has terminated. The settlement excluded 30 citations for
which BP and OSHA could not reach agreement. However, the parties
agreed that BP’s penalty liability will not exceed $1 million if those
citations are resolved through litigation. On 4 March 2014, the parties
reached agreement in relation to the remaining Texas City citations. The
agreement, which is subject to approval by an Administrative Law Judge
from the OSH Review Commission, links the outcome of the remaining
Texas City citations to the ultimate outcome of the remaining Toledo
citations (see below). If the 31 July 2013 decision of the Administrative
Law Judge in relation to the remaining Toledo citations is ultimately
upheld, OSHA has agreed to dismiss the remaining Texas City citations.
If the 31 July 2013 decision is ultimately overturned, BP has agreed to
pay a penalty not exceeding $1 million to resolve the remaining Texas
City citations.
On 8 March 2010, OSHA issued 65 citations to BP Products and BP-
Husky for alleged violations of the PSM Standard at the Toledo refinery,
with penalties of approximately $3 million. These citations resulted from
an inspection conducted pursuant to OSHA’s Petroleum Refinery
Process Safety Management National Emphasis Program. Both BP
Products and BP-Husky contested the citations. The parties resolved
23 citations in a pre-trial settlement for an aggregate amount of $45,000.
A trial of the remaining 42 citations was completed in June 2012 before
an Administrative Law Judge from the OSH Review Commission. The
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Administrative Law Judge rendered her decision on 31 July 2013. Of the
42 remaining citations, OSHA voluntarily dismissed one of them and the
judge vacated 36 additional citations. The remaining five citations were
downgraded and assessed an aggregate penalty of $35,000. In addition,
the judge accepted the parties’ pre-trial settlement of the 23 citations. As
a result of the settlement and the judge’s decision, the total penalty in
respect of the citations was reduced from the original amount of
approximately $3 million to $80,000. The Review Commission has
granted OSHA’s petition for review with briefing scheduled to be
completed in the first half of 2014. The Review Commission is not
expected to issue its decision until 2015.
Texas City flaring event
A flaring event occurred at the Texas City refinery in April and May 2010.
This flaring event is the subject of civil lawsuit claims for personal injury
and, in some cases, property damage by roughly 50,000 individuals.
These lawsuit claims have been consolidated in a Texas multi-district
litigation proceeding in Galveston, Texas. The first trial in the matter
began in September 2013 and was completed in October 2013. Of the
six plaintiffs initially scheduled for trial, two filed nonsuits before trial, the
claims of one plaintiff were dismissed by the court on directed verdict,
and the jury awarded no damages to the remaining three plaintiffs. The
second trial in the matter is scheduled to begin on 15 September 2014. In
addition, this flaring event and other refinery emissions from December
2008 through to 2010 were the subject of a purported class action, on
behalf of some local residential property owners, filed in US federal
district court in Galveston. The court denied the plaintiffs’ class
certification motion on 2 October 2013, and the plaintiffs dismissed their
complaint on 4 December 2013. The flares involved in this event are also
the subject of a federal government enforcement action. BP retained
these liabilities when it sold the Texas City refinery.
Prudhoe Bay leak
In March and August 2006, oil leaked from oil transit pipelines operated
by BP Exploration (Alaska) Inc. (BPXA) at the Prudhoe Bay unit on the
North Slope of Alaska. On 12 May 2008, a BP p.l.c. shareholder filed a
consolidated complaint alleging violations of federal securities law on
behalf of a putative class of BP p.l.c. shareholders against BP p.l.c.,
BPXA, BP America Inc., and four officers of the companies, based on
alleged misrepresentations concerning the integrity of the Prudhoe Bay
pipeline before its shutdown on 6 August 2006. On 8 February 2010, the
US Court of Appeals for the Ninth Circuit (the Ninth Circuit) accepted
BP’s appeal from a decision of the lower court granting in part and
denying in part BP’s motion to dismiss the lawsuit. On 29 June 2011, the
Ninth Circuit ruled in BP’s favour that the filing of a trust-related
agreement with the SEC containing contractual obligations on the part of
BP was not a misrepresentation which violated federal securities laws.
The BP p.l.c. shareholder filed an amended complaint, in response to
which BP filed a new motion to dismiss, which was granted by the trial
court on 14 March 2012. The plaintiff appealed the court’s dismissal of
the case, and on 13 February 2014 the Ninth Circuit affirmed in part and
reversed in part, ruling that claims based on four alleged
misrepresentations should not have been dismissed. The case has been
remanded to the trial court for further proceedings.
Exxon Valdez matters
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 that own Alyeska. Alyeska initially responded to the
spill until the response was taken over by Exxon. BP owns a 46.9%
interest (reduced during 2001 from 50% by a sale of 3.1% to Phillips) in
Alyeska through a subsidiary of BP America Inc. and briefly indirectly
owned a further 20% interest in Alyeska following BP’s combination with
Atlantic Richfield. 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 that it has incurred. If any claims are asserted by Exxon that
affect Alyeska and its owners, BP will defend the claims vigorously.
Lead paint matters
Since 1987, Atlantic Richfield Company (Atlantic Richfield), a subsidiary of
BP, has been named as a co-defendant in numerous lawsuits brought in
the US alleging injury to persons and property caused by lead pigment in
paint. The majority of the lawsuits have been abandoned or dismissed
against Atlantic Richfield. Atlantic Richfield is named in these lawsuits as
alleged successor to International Smelting and Refining and another
company that manufactured lead pigment during the period 1920-1946.
The plaintiffs include individuals and governmental entities. Several of the
lawsuits purport to be class actions. The lawsuits 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 lawsuit against Atlantic
Richfield has been settled nor has Atlantic Richfield been subject to a
final adverse judgment in any proceeding. The amounts claimed and, if
such suits were successful, the costs of implementing the remedies
sought in the various cases could be substantial. While it is not possible
to predict the outcome of these legal actions, Atlantic Richfield believes
that it has valid defences. It intends to defend such actions vigorously
and believes that the incurrence of liability is remote. Consequently, BP
believes that the impact of these lawsuits on the group’s results, financial
position or liquidity will not be material.
Abbott Atlantis related matters
In April 2009, Kenneth Abbott, as relator, filed a US False Claims Act
lawsuit against BP, alleging that BP violated federal regulations, and
made false statements in connection with its compliance with those
regulations, by failing to have necessary documentation for the Atlantis
subsea and other systems. BP is the operator and 56% interest owner of
the Atlantis unit in production in the Gulf of Mexico. That complaint was
unsealed in May 2010 and served on BP in June 2010. Abbott seeks
damages measured by the value, net of royalties, of all past and future
production from the Atlantis platform, trebled, plus penalties. In
September 2010, Kenneth Abbott and Food & Water Watch filed an
amended complaint in the False Claims Act lawsuit seeking an injunction
shutting down the Atlantis platform. The court denied BP’s motion to
dismiss the complaint in March 2011. Separately, also in March 2011,
BOEMRE issued its investigation report of the Abbott Atlantis allegations,
which concluded that Kenneth Abbott’s allegations that Atlantis
operations personnel lacked access to critical, engineer-approved
drawings were without merit and that his allegations about false
submissions by BP to BOEMRE were unfounded. Trial was scheduled to
begin on 10 April 2012, but the trial date was vacated and not
rescheduled pending consideration of the parties’ summary judgment
motions.
Clean Air Act matters
On 1 February 2013, Marathon Petroleum Company LP (Marathon)
purchased the Texas City refinery from BP Products and directed BP
Products to transfer the refinery to Blanchard Refining Company LLC
(Blanchard). On 4 November 2013, BP Products, Blanchard and the EPA
reached an agreement to settle certain alleged Clean Air Act violations at
the Texas City refinery. Pursuant to the settlement BP Products paid a
civil penalty of $950,000 and Blanchard agreed to undertake certain
injunctive relief.
BP Products has also been in discussions with the EPA regarding alleged
CAA violations at the Toledo refinery and the EPA has alleged certain
CAA violations at the Cherry Point refinery and the Carson refinery (which
BP Products sold to Tesoro Corporation on 1 June 2013).
Bolivia
On 24 January 2012, the Republic of Bolivia issued a press statement
declaring its intent to nationalize Pan American Energy’s (PAE) interests
in the Caipipendi Operations Contract. No formal decision has been
issued or announced by the government, and no nationalization process
has commenced. In October 2013, in a public speech the President of
Bolivia made remarks in connection with PAE’s arbitration case for
compensation for expropriation of its shares in Empresa Petrolera Chaco
S.A. (Chaco). PAE and its shareholders BP and Bridas intend to vigorously
defend their legal interests under the Caipipendi Operations Contract and
in relation to the arbitration case relating to the expropriation of the PAE
shares in Chaco. That arbitration was filed in March 2012 and jurisdiction
has been confirmed by the tribunal. The case is due to proceed. PAE has
reiterated its willingness to negotiate on the Chaco compensation claim
and in December 2013 there was an agreement in principle to explore
settlement options with the Bolivian government. Such proposals are
being evaluated.
EC investigation and related matters
On 14 May 2013, European Commission officials made a series of
unannounced inspections at the offices of BP and other companies
involved in the oil industry acting on concerns that anticompetitive
practices may have occurred in connection with oil price reporting
practices and the reference price assessment process. Such inspections
are a preliminary step in investigations. There is no deadline for the
completion of the inquiries. Related inquiries and requests for information
have also been received from US and other regulators following the
European Commission’s actions. On 25 June 2013, the Federal Trade
Commission (FTC) served BP with a Request for Voluntary Submission of
Documents and Information regarding its non-public investigation into
whether or not Shell, BP or Statoil have engaged in unfair methods of
competition or manipulative or deceptive conduct. BP is producing
documents to the FTC. In June 2013, BP received an initial request for
information from the Japanese Fair Trade Commission. In
December 2013, the Korea Fair Trade Commission initiated an
investigation and a first information request is expected to be issued. On
16 January 2014, the U.S. Commodity Futures Trading Commission
requested price reporting documents from BP.
In addition, fifteen purported class actions related to these matters have
been filed in US District Courts alleging manipulation and antitrust
violations under the Commodity Exchange Act and US antitrust laws, and
these purported class actions have been consolidated in federal court in
New York.
Further note on certain activities
During the period covered by this report, non-US subsidiaries or other
non-US entities of BP conducted limited activities in, or with persons
from, certain countries identified by the US Department of State as State
Sponsors of Terrorism or otherwise subject to US sanctions (‘Sanctioned
Countries’). These activities continue to be insignificant to the group’s
financial condition and results of operations. BP monitors its activities
with Sanctioned Countries and persons from Sanctioned Countries and
seeks to comply with applicable sanctions laws and regulations.
Both the US and the EU have enacted strong sanctions against Iran,
including: in the US, sanctions against persons involved with Iran’s
energy, shipping and petrochemicals industries, and sanctions against
financial institutions that engage in significant transactions with the Iran
Central Bank; and in the EU, a prohibition on the import, purchase and
transport of Iranian-origin crude oil, petroleum products and natural gas.
In addition, in August 2012, US President Obama signed into law the Iran
Threat Reduction and Syria Human Rights Act of 2012 (‘ITRA’), which,
among other things, added a new Section 13(r) to the Securities
Exchange Act of 1934, as amended (the ‘Exchange Act’) and requires
issuers that must file annual or quarterly reports under the Exchange Act
to disclose in such reports whether, during the period covered by the
report, the registrant or its affiliates have knowingly engaged in certain,
principally Iran-related, activities.
Both the US and the EU have enacted strong sanctions against Syria,
including a prohibition on the purchase of Syrian-origin crude and a US
prohibition on the provision of services to Syria by US persons. The EU
sanctions against Syria include a prohibition on supplying certain
equipment used in the production, refining, or liquefaction of petroleum
resources as well as restrictions on dealing with the Central Bank of Syria
and numerous other Syrian financial institutions.
With effect from 20 January 2014, the US and the EU implemented
temporary, limited and reversible relief of certain sanctions related to Iran
pursuant to a Joint Plan of Action entered by Iran, China, France,
Germany, Russia, the UK and the US. BP has not changed its policy in
relation to Iran as a result of the Joint Plan of Action and has no plans to
engage in any new business with Iran which would now be permitted as
a result of the Joint Plan of Action.
BP has interests in and operates two fields – the North Sea Rhum field
(‘Rhum’) and the Azerbaijan Shah Deniz field – and has interests in a gas
marketing entity and a gas pipeline entity which, respectively, market and
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transport Shah Deniz gas (both entities and related assets are located
outside Iran), in which Naftiran Intertrade Co. Limited and NICO SPV
Limited (collectively, ‘NICO’) or Iranian Oil Company (U.K.) Limited
(‘IOC UK’) have interests. Production was suspended at Rhum (in which
IOC UK has a 50% interest) in November 2010 and Rhum remains shut-
in. On 22 October 2013, the UK government announced a temporary
management scheme (the ‘Temporary Scheme’) under The Hydrocarbon
(Temporary Management Scheme) Regulations 2013 under which the
UK government will assume control of and manage IOC UK’s interest in
the Rhum field, thereby permitting operations to re-commence at Rhum
in accordance with applicable EU regulations and in compliance with US
laws and regulations.
The Shah Deniz field, its gas marketing entity and the gas pipeline entity
(in which NICO has a 10% or less non-operating interest) continue in
operation. The Shah Deniz joint operation and its gas marketing and
pipeline entities were excluded from the main operative provisions of the
EU regulations as well as from the application of the new US sanctions,
and fall within the exception for certain natural gas projects under
Section 603 of ITRA.
BP has no operations in Iran and it is BP’s policy that it shall not purchase
or ship crude oil or other products of Iranian origin. Participants in non-BP
controlled or operated joint ventures may purchase Iranian-origin crude oil
or other components as feedstock for facilities located outside the EU
and US. It is also BP’s policy that BP shall not sell crude oil or other
products into Iran. Until January 2010, BP held an equity interest in an
Iranian joint venture that blended and marketed automotive lubricants for
sale to domestic consumers in Iran. BP sold its equity interest but
continued to sell small quantities of automotive lubricants and
components and license relevant trade marks to the current owner.
These sales of automotive lubricants and components were terminated
in June 2013. BP currently holds an interest in a non-BP operated joint
venture which sells crude oil to an Indian entity in which NICO holds a
minority, non-controlling stake.
In 2012, BP became aware that a Canadian university had been using
graduate students, some of whom were nationals of Iran, on a research
programme funded in part by BP. BP suspended the programme and
made a voluntary disclosure to OFAC. Also in 2012, BP became aware
that in 2010, as consideration for certain auditing services, BP effected a
transfer of funds to a local Iranian consulting firm which may have been
in violation of relevant EU notification requirements. BP has made a
voluntary disclosure to the applicable EU regulator of such transfer.
Following the imposition in 2011 of further US and EU sanctions against
Syria, BP terminated all sales of crude oil and petroleum products into
Syria, though BP continues to supply aviation fuel to non-governmental
Syrian resellers outside of Syria.
BP sells lubricants in Cuba through a 50:50 joint arrangement and trades
in small quantities of lubricants. In the first quarter of 2013, BP sold a
small quantity of lubricants to a third-party drilling company for use in
Myanmar.
BP has equity interests in non-operated joint arrangements with air fuel
sellers, resellers, and fuel delivery services around the world. From time
to time, the joint arrangement operator may sell or deliver fuel to airlines
from Sanctioned Countries or flights to Sanctioned Countries without
BP’s knowledge or consent. BP has registered and paid required fees for
patents and trade marks in Sanctioned Countries.
Disclosure pursuant to Section 219 of ITRA
To our knowledge, none of BP’s activities, transactions or dealings are
required to be disclosed pursuant to ITRA Section 219, with the following
possible exception:
The Rhum field (‘Rhum’), located in the UK sector of the North Sea, is
operated by BP Exploration Operating Company Limited (‘BPEOC’), a
non-US subsidiary of BP. Rhum is owned under a 50:50 unincorporated
joint arrangement between BPEOC and Iranian Oil Company (U.K.)
Limited (‘IOC’). The Rhum joint arrangement was originally formed in
1974. During the period of production from Rhum, the Rhum joint
arrangement supplied natural gas and certain associated liquids to the
UK. On 16 November 2010, production from Rhum was suspended in
response to relevant EU sanctions. Rhum remains shut-in.
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During the year ended 31 December 2013, BP recorded gross revenues
of $5,297 related to Rhum due to changes in prices related to
hydrocarbon stock. These changes in prices were non-cash transactions
that were recorded as revenue in accordance with BP accounting policy.
BP had no net profits related to Rhum during the year ended
31 December 2013, recording an overall loss.
The re-commencement of operations at Rhum in accordance with the
Temporary Scheme (see above) remains contingent on the commitment
of third-party contractors and financial institutions to provide services to
Rhum. BP currently intends to continue to hold its ownership stake in the
Rhum joint arrangement, and to meet any applicable obligations in
respect of safety and maintenance of the facilities related to the Rhum
field. Subject to the availability of the Temporary Scheme in the future
and to the commitment of relevant third-party contractors and financial
institutions to provide services to Rhum, BP also intends to recommence
operations at Rhum in the future in accordance with the Temporary
Scheme.
Material contracts
On 6 August 2010, BP entered into a trust agreement with John S Martin, Jr
and Kent D Syverud, as individual trustees, and Citigroup Trust – Delaware,
N.A., as corporate trustee (the Trust Agreement) which established the
Deepwater Horizon Oil Spill Trust (the Trust) to be funded in the amount of
$20 billion (the trust fund) over the period to the fourth quarter of 2013.
During the fourth quarter of 2012, BP made a final contribution to the Trust
to complete the funding of the full $20-billion commitment. The trust fund is
available to satisfy legitimate individual and business claims that were
previously administered by the Gulf Coast Claims Facility (GCCF), state and
local government claims resolved by BP, final judgments and settlements,
state and local response costs, and natural resource damages and related
costs. The trust fund is available to satisfy claims that were previously
processed through the transitional court-supervised claims facility, to fund
the qualified settlement funds established under the terms of the settlement
agreements with the Plaintiffs’ Steering Committee (PSC) administered
through the court-supervised settlement programme, and to satisfy claims
processed through the separate BP claims programme in respect of
claimants not in the Economic and Property Damages class as determined
by the Economic and Property Damages Settlement Agreement or who
have requested to opt out of that settlement. Fines, penalties and claims
administration costs are not covered by the trust fund. Under the terms of
the Trust Agreement, BP has no right to access the funds once they have
been contributed to the trust fund. BP will receive funds from the trust fund
only upon its expiration, if there are any funds remaining at that point. BP has
the authority under the Trust Agreement to present certain resolved claims,
including natural resource damages claims and state and local response
claims, to the Trust for payment, by providing the trustees with all the
required documents establishing that such claims are valid under the Trust
Agreement. However, any such payments can only be made on the
authority of the trustee and any funds distributed are paid directly to the
claimants, not to BP. The Trust Agreement is governed by the laws of the
State of Delaware.
Property, plant and equipment
BP has freehold and leasehold interests in real estate in numerous
countries, but no individual property is significant to the group as a whole.
For more on the significant subsidiaries of the group at 31 December
2013 and the group percentage of ordinary share capital see Financial
statements – Note 38. For information on significant joint ventures and
associates of the group see Financial statements – Notes 17 and 18.
Related-party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 17 and Note
18. In the ordinary course of its business, the group enters into
transactions with various organizations with which some of its directors
or executive officers are associated. Except as described in this report,
the group did not have material transactions or transactions of an unusual
nature with, and did not make loans to, related parties in the period
commencing 1 January 2013 to 18 February 2014.
Exhibits
The following documents are filed in the Securities and Exchange
Commission (SEC) EDGAR system, as part of this Annual Report on
Form 20-F, and can be viewed on the SEC’s website.
Exhibit 1
Exhibit 4.1
Exhibit 4.2
Exhibit 4.3
Exhibit 4.4
Exhibit 4.6
Exhibit 4.7
Exhibit 7
Exhibit 8
Exhibit 10.1
Exhibit 11
Exhibit 12
Exhibit 13
Exhibit 15.1
Exhibit 15.2
Memorandum and Articles of Association of BP
p.l.c.*†
The BP Executive Directors’ Incentive Plan*†
Amended BP Deferred Annual Bonus Plan 2005**†
Amended Director’s Secondment Agreement for
R W Dudley†
Amended Director’s Service Contract and Secondment
Agreement for R W Dudley*†
Director’s Service Contract for I C Conn***†
Director’s Service Contract for Dr B Gilvary****†
Computation of Ratio of Earnings to Fixed Charges
(Unaudited)†
Subsidiaries (included as Note 38 to the Financial
Statements)
Trust Agreement dated as of 6 August 2010 among BP
Exploration & Production Inc., John S Martin, Jr and
Kent D Syverud, as individual trustees, and Citigroup
Trust- Delaware, N.A., as corporate trustee, as
amended by an Addendum, dated 6 August 2010*†
Code of Ethics*****†
Rule 13a – 14(a) Certifications†
Rule 13a – 14(b) Certifications#†
Consent of DeGolyer and MacNaughton†
Report of DeGolyer and MacNaughton†
* Incorporated by reference to the company’s Annual Report on Form 20-F for the year
ended 31 December 2010.
** Incorporated by reference to the company’s Annual Report on Form 20-F for the year
ended 31 December 2012.
*** Incorporated by reference to the company’s Annual Report on Form 20-F for the year
ended 31 December 2004.
**** Incorporated by reference to the company’s Annual Report on Form 20-F for the year
ended 31 December 2011.
***** Incorporated by reference to the company’s Annual Report on Form 20-F for the year
ended 31 December 2009.
# Furnished only.
† Included only in the annual report filed in the Securities and Exchange Commission
EDGAR system.
The total amount of long-term 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 SEC on request.
Certain definitions
Unless the context indicates otherwise, the following terms have the
meaning provided below:
Replacement cost profit
Replacement cost (RC) profit or loss reflects the replacement cost of
supplies and is arrived at by excluding inventory holding gains and losses
from profit or loss. IFRS requires that the measure of profit or loss
disclosed for each operating segment is the measure that is provided
regularly to the chief operating decision maker for the purposes of
performance assessment and resource allocation. For BP, both RC profit
or loss before interest and tax and underlying RC profit or loss before
interest and tax are provided regularly to the chief operating decision
maker. In such cases IFRS requires that the measure of profit disclosed
for each operating segment is the measure that is closest to IFRS, which
for BP is RC profit or loss before interest and tax. RC profit or loss for the
group is not a recognized GAAP measure. The nearest equivalent GAAP
measure is profit or loss for the year attributable to BP shareholders. BP
believes that replacement cost profit before interest and taxation for the
group is a useful measure for investors because it is a profitability
measure used by management. A reconciliation is provided between the
total of the operating segments’ measures of profit or loss and the group
profit or loss before taxation, as required under IFRS. See Financial
statements – Note 7.
Inventory holding gains and losses
Inventory holding gains and losses represent the difference between the
cost of sales calculated using the average cost to BP of supplies acquired
during the period and the cost of sales calculated on the first-in first-out
(FIFO) method after adjusting for any changes in provisions where the
net realizable value of the inventory is lower than its cost. Under the FIFO
method, which we use for IFRS reporting, the cost of inventory charged
to the income statement is based on its historic cost of purchase, or
manufacture, rather than its replacement cost. In volatile energy markets,
this can have a significant distorting effect on reported income. The
amounts disclosed represent the difference between the charge (to the
income statement) for inventory on a FIFO basis (after adjusting for any
related movements in net realizable value provisions) and the charge that
would have arisen if an average cost of supplies was used for the period.
For this purpose, the average cost of supplies during the period is
principally calculated on a monthly basis by dividing the total cost of
inventory acquired in the period by the number of barrels acquired. The
amounts disclosed are not separately reflected in the financial
statements as a gain or loss. No adjustment is made in respect of the
cost of inventories held as part of a trading position and certain other
temporary inventory positions.
Management believes this information is useful to illustrate to investors
the fact that crude oil and product prices can vary significantly from
period to period and that the impact on our reported result under IFRS
can be significant. Inventory holding gains and losses vary from period to
period due principally to changes in oil prices as well as changes to
underlying inventory levels. In order for investors to understand the
operating performance of the group excluding the impact of oil price
changes on the replacement of inventories, and to make comparisons of
operating performance between reporting periods, BP’s management
believes it is helpful to disclose this information.
Underlying replacement cost profit
Underlying RC profit or loss is RC profit or loss after adjusting for non-
operating items and fair value accounting effects. Underlying RC profit or
loss and fair value accounting effects are not recognized GAAP
measures. On pages 237 and 238 we provide additional information on
the non-operating items and fair value accounting effects that are used to
arrive at underlying RC profit or loss in order to enable a full
understanding of the events and their financial impact.
BP believes that underlying RC profit or loss before interest and taxation
is a useful measure for investors because it is a measure closely tracked
by management to evaluate BP’s operating performance and to make
financial, strategic and operating decisions and because it may help
investors to understand and evaluate, in the same manner as
management, the underlying trends in BP’s operational performance on a
comparable basis, year on year, by adjusting for the effects of these non-
operating items and fair value accounting effects. The nearest equivalent
measure on an IFRS basis for the group is profit or loss for the year
attributable to BP shareholders. The nearest equivalent measure on an
IFRS basis for segments is RC profit or loss before interest and taxation.
Non-GAAP information on fair value accounting effects
BP uses derivative instruments to manage the economic exposure
relating to inventories above normal operating requirements of crude oil,
natural gas and petroleum products. Under IFRS, these inventories are
recorded at historic cost. The related derivative instruments, however,
are required to be recorded at fair value with gains and losses recognized
in income because hedge accounting is either not permitted or not
followed, principally due to the impracticality of effectiveness testing
requirements. Therefore, measurement differences in relation to
recognition of gains and losses occur. Gains and losses on these
inventories are not recognized until the commodity is sold in a
subsequent accounting period. Gains and losses on the related derivative
commodity contracts are recognized in the income statement from the
time the derivative commodity contract is entered into on a fair value
basis using forward prices consistent with the contract maturity.
BP enters into commodity contracts to meet certain business
requirements, such as the purchase of crude for a refinery or the sale of
BP’s gas production. Under IFRS these contracts are treated as
derivatives and are required to be fair valued when they are managed as
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part of a larger portfolio of similar transactions. Gains and losses arising
are recognized in the income statement from the time the derivative
commodity contract is entered into.
under the contracts in cash rather than through physical delivery.
Additionally, the BFO contract specifies a standard volume and tolerance
given that the physically settled transactions are delivered by cargo.
IFRS requires that inventory held for trading be recorded at its fair value
using period-end spot prices whereas any related derivative commodity
instruments are required to be recorded at values based on forward
prices consistent with the contract maturity. Depending on market
conditions, these forward prices can be either higher or lower than spot
prices resulting in measurement differences.
BP enters into contracts for pipelines and storage capacity, oil and gas
processing and liquefied natural gas (LNG) that, under IFRS, are recorded
on an accruals basis. These contracts are risk-managed using a variety of
derivative instruments, which are fair valued under IFRS. This results in
measurement differences in relation to recognition of gains and losses.
The way that BP manages the economic exposures described above, and
measures performance internally, differs from the way these activities
are measured under IFRS. BP calculates this difference for consolidated
entities by comparing the IFRS result with management’s internal
measure of performance. Under management’s internal measure of
performance the inventory and capacity contracts in question are valued
based on fair value using relevant forward prices prevailing at the end of
the period, the fair values of certain derivative instruments used to risk
manage LNG and oil and gas processing contracts are deferred to match
with the underlying exposure and the commodity contracts for business
requirements are accounted for on an accruals basis. We believe that
disclosing management’s estimate of this difference provides useful
information for investors because it enables investors to see the
economic effect of these activities as a whole.
Commodity trading contracts
BP’s Upstream and Downstream segments both participate in regional
and global commodity trading markets in order to manage, transact and
hedge the crude oil, refined products and natural gas that the group
either produces or consumes in its manufacturing operations. These
physical trading activities, together with associated incremental trading
opportunities, are discussed further in Upstream on page 25 and in
Downstream on page 31. The range of contracts the group enters into in
its commodity trading operations is described below. Using these
contracts, in combination with rights to access storage and transportation
capacity, allows the group to access advantageous pricing differences
between locations, time periods and arbitrage between markets.
Exchange-traded commodity derivatives
These contracts are typically in the form of futures and options traded on
a recognized exchange, such as Nymex, SGX and ICE. Such contracts are
traded in standard specifications for the main marker crude oils, such as
Brent and West Texas Intermediate, the main product grades, such as
gasoline and gasoil, and for natural gas and power. Gains and losses,
otherwise referred to as variation margins, are settled on a daily basis
with the relevant exchange. These contracts are used for the trading and
risk management of crude oil, refined products, natural gas and power.
Realized and unrealized gains and losses on exchange-traded commodity
derivatives are included in sales and other operating revenues for
accounting purposes.
Over-the-counter contracts
These contracts are typically in the form of forwards, swaps and options.
Some of these contracts are traded bilaterally between counterparties or
through brokers; others may be cleared by a central clearing
counterparty. These contracts can be used both for trading and risk
management activities. Realized and unrealized gains and losses on over-
the-counter (OTC) contracts are included in sales and other operating
revenues for accounting purposes. Many grades of crude oil bought and
sold use standard contracts including US domestic light sweet crude oil,
commonly referred to as West Texas Intermediate, and a standard North
Sea crude blend (Brent, Forties and Oseberg or BFO). Forward contracts
are used in connection with the purchase of crude oil supplies for
refineries, purchases of products for marketing, sales of the group’s oil
production and refined product. The contracts typically contain standard
delivery and settlement terms. These transactions call for physical
delivery of oil with consequent operational and price risk. However,
various means exist, and are from time to time used, to settle obligations
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Gas and power OTC markets are highly developed in North America and
the UK, where the commodities can be bought and sold for delivery in
future periods. These contracts are negotiated between two parties to
purchase and sell gas and power at a specified price, with delivery and
settlement at a future date. Typically, these contracts specify delivery
terms for the underlying commodity. Certain of these transactions are not
settled physically, which can be achieved by transacting offsetting sale or
purchase contracts for the same location and delivery period that are
offset during the scheduling of delivery or dispatch. The contracts contain
standard terms such as delivery point, pricing mechanism, settlement
terms and specification of the commodity. Typically, volume, price and
term (e.g. daily, monthly and balance of month) are the main variable
contract terms.
Swaps are often contractual obligations to exchange cash flows between
two parties: a typical swap transaction usually references a floating price
and a fixed price with the net difference of the cash flows being settled.
Options give the holder the right, but not the obligation, to buy or sell
crude, oil products, natural gas or power at a specified price on or before
a specific future date. Amounts under these derivative financial
instruments are settled at expiry. Typically, netting agreements are used
to limit credit exposure and support liquidity.
Spot and term contracts
Spot contracts are contracts to purchase or sell a commodity at the
market price prevailing on or around the delivery date when title to the
inventory is taken. Term contracts are contracts to purchase or sell a
commodity at regular intervals over an agreed term. Though spot and
term contracts may have a standard form, there is no offsetting
mechanism in place. These transactions result in physical delivery with
operational and price risk. Spot and term contracts typically relate to
purchases of crude for a refinery, purchases of products for marketing,
purchases of third-party natural gas, sales of the group’s oil production,
sales of the group’s oil products and sales of the group’s gas production
to third parties. For accounting purposes, spot and term sales are
included in sales and other operating revenues, when title passes.
Similarly, spot and term purchases are included in purchases for
accounting purposes.
Associate
An entity, including an unincorporated entity such as a partnership, over
which the group has significant influence and that is neither a subsidiary
nor a joint arrangement of the group. Significant influence is the power to
participate in the financial and operating policy decisions of the investee
but is not control or joint control over those policies.
Joint arrangement
A joint arrangement is an arrangement of which two or more parties have
joint control.
Joint control
Joint control is the contractually agreed sharing of control over an
arrangement, which exists only when decisions about the relevant
activities require the unanimous consent of the parties sharing control.
Joint operation
A joint operation is a joint arrangement whereby the parties that have
joint control of the arrangement have rights to the assets, and obligations
for the liabilities, relating to the arrangement.
Joint venture
A joint arrangement whereby the parties that have joint control of the
arrangement have rights to the net assets of the arrangement.
Subsidiary
An entity that is controlled by the BP group. Control of an investee exists
when an investor is exposed, or has rights, to variable returns from its
involvement with the investee and has the ability to affect those returns
through its power over the investee.
PSA
A production-sharing agreement (PSA) is an arrangement through which
an oil company bears the risks and costs of exploration, development and
production. In return, if exploration is successful, the oil company
receives entitlement to variable physical volumes of hydrocarbons,
representing recovery of the costs incurred and a stipulated share of the
production remaining after such cost recovery.
Directors’ report information
This section of BP Annual Report and Form 20-F 2013 forms part of, and
includes certain disclosures which are required by law to be included in,
the Directors’ report.
Indemnity provisions
In accordance with BP’s Articles of Association, each director is granted
an indemnity from the company in respect of liabilities incurred as a
result of their office, to the extent permitted by law. These indemnities
were in force throughout the financial year and at the date of this report.
In respect of those liabilities for which directors may not be indemnified,
the company maintained a directors’ and officers’ liability insurance
policy throughout 2013. During the year, a review of the terms and
scope of the policy was undertaken. The policy has been renewed for
2014. Although their defence costs may be met, neither the company’s
indemnity nor insurance provides cover in the event that the director is
proved to have acted fraudulently or dishonestly. In addition, each
director of the company’s subsidiaries, which subsidiaries are trustees
of the group’s pension schemes, is granted an indemnity from the
company in respect of liabilities incurred as a result of such a
subsidiary’s activities as a trustee of the pension scheme, to the extent
permitted by law. These indemnities were in force throughout the
financial year and at the date of this report.
Financial risk management objectives and policies
The disclosures in relation to financial risk management objectives and
policies, including the policy for hedging, are included in Our
management of risk on page 49 and Liquidity and capital resources on
page 56.
Exposure to price risk, credit risk, liquidity risk and cash
flow risk
The disclosures in relation to exposure to price risk, credit risk, liquidity
risk and cash flow risk are included in Financial statements – Note 19.
Important events since the end of the financial year
Disclosures of the particulars of the important events affecting BP which
have occurred since the end of the financial year are included in the
Strategic report as well as in other places in the Directors’ report.
Likely future developments in the business
An indication of the likely future developments of the business is
included in the Strategic report.
Research and development
An indication of the activities of the company in the field of research and
development is included in Our strategy on page 13.
Branches
As a global group our interests and activities are held or operated through
subsidiaries, branches, joint arrangements or associates established in –
and subject to the laws and regulations of – many different jurisdictions.
Employees
The disclosures concerning policies in relation to the employment of
disabled persons and employee involvement are included in Corporate
responsibility – Employees on page 47.
Greenhouse gas emissions
The disclosures in relation to greenhouse gas emissions are included in
Corporate responsibility – Environment and society on page 45.
Cautionary statement
This document contains certain forecasts, projections and forward-looking
statements – that is, statements related to future, not past events – with
respect to the financial condition, results of operations and businesses 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’, ‘aims’, ‘should’,
‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’, ‘we
see’ or similar expressions. In particular, among other statements, (i) certain
statements in the Chairman’s letter (pages 6-7), the Group chief executive’s
letter (pages 8-9), the Strategic report (pages 1-58) and Additional
disclosures (pages 235-272), including but not limited to statements under
the headings ‘Our market outlook’, ‘Beyond 2035’, ‘Our business model’,
‘Our strategy’, ‘Outlook’ and ‘Looking ahead’, and including but not limited
to statements regarding plans to optimize BP’s portfolio of assets,
expectations regarding future distributions to shareholders, the estimated
levels of capital expenditure in 2014, the expected levels of capital
expenditure from 2015 to 2018, plans regarding the future divestment of
$10 billion in assets by the end of 2015 and the prospects for and timing of
planned and future divestments, prospects for future value creation arising
from certain of BP’s new investments in 2013, BP’s outlook on global
energy trends to 2035 and beyond, including the role of oil, gas and
renewables in coming decades, plans to make disciplined financial choices,
including the disciplined allocation of capital, expectations regarding the ‘10-
point plan’, plans to explore future opportunities with Rosneft, the
anticipated delivery of an increase in operating cash flow by more than
50% by 2014 versus 2011 and expectations regarding growth in
sustainable free cash flow beyond 2014, the expected implementation in
the future of lessons learned from the In Amenas terrorist attacks, the
expected design-life of the field at Valhall, plans to grow BP’s exploration
position and focus on high-value upstream assets in deep water, giant
fields and selected gas value chains, expectations regarding financial
momentum from the assets portfolio in the future, plans to grow free cash
flow by leveraging newly upgraded assets, customer relationships and
technology in the downstream business, plans to create shareholder value
and increase sustainable free cash flows, plans and expectations regarding
Project 20K, LoSal technology, the ‘virtual arrival system’, Veba Combi-
Cracking technology and SaaBre and Hummingbird technologies, plans
relating to future hiring and workforce, expectations that the 2014 start-ups
will have double the 2011 average unit operating cash margins, the
expected target net debt ratio in 2014 and beyond, the expected level of
depreciation, depletion and amortization in the future, the expected level of
the underlying effective tax rate in 2014, plans to generate $30 billion to
$31 billion of operating cash flow in 2014, plans to use around half of the
extra cash in 2014 for increased investments and around half for other
purposes including distributions, the expected levels of full-year underlying
and reported production in 2014, expectations regarding BP’s plans to
separate its US Lower 48 onshore oil and gas business, including the
timing thereof and the expected impact on BP’s resource position and
portfolio in the future, the prospects for movement in and the levels of oil
and gas prices in 2014, the timing and composition of planned and future
projects including expected final investment decisions, start up,
construction, commissioning, completion, timing of production, level of
production and margins, plans for gas discovery and production in India,
plans to enhance safety, compliance and risk management, increase
efficiency and reliability, improve margins and create new market
opportunities, expectations regarding and plans to deliver a strong
performance in safety, portfolio management, competitive returns and
material and growing cash flows in the Downstream segment,
expectations regarding refining margins in 2014, the expected impact of
refinery turnarounds in 2014, expectations regarding the market
environments for lubricants and petrochemicals in 2014, plans to increase
lubricant revenues in the future, the expected level of heavy crude
processing at the Whiting refinery during the second quarter 2014 and
Whiting’s prospects for supporting BP’s ability to deliver increased cash
flow in 2014 and beyond, plans to continue to develop biofuel blend
capabilities, BP’s plans for LPG in the future, Air BP’s future strategic aims,
the timing of first production at the third PTA plant at Zhuhai and the
expected capacity thereof in the future, expectations regarding the material
impacts of investments in Asia and the deployment of new PTA technology
in existing plants and new asset platforms, plans to access Asian demand
and feedstock sources, expectations for the environment for PTA, acetic
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maintenance and/or turnaround activity; the timing and volume of refinery
additions and outages; the timing of bringing new fields onstream; the
timing, quantum and nature of certain divestments; future levels of industry
product supply, demand and pricing, including supply growth in North
America; OPEC quota restrictions; PSA effects; operational problems;
economic and financial market conditions generally or in various countries
and regions; political stability and economic growth in relevant areas of the
world; changes in laws and governmental regulations; regulatory or legal
actions including the types of enforcement action pursued and the nature
of remedies sought or imposed; the actions of prosecutors, regulatory
authorities and courts; the impact on our reputation following the Gulf of
Mexico oil spill; the actions of the Claims Administrator appointed under the
Economic and Property Damages Settlement; the actions of all parties to
the Gulf of Mexico oil spill-related litigation at various phases of the
litigation; exchange rate fluctuations; development and use of new
technology; the success or otherwise of partnering; the actions of
competitors, trading partners, creditors, rating agencies and others;
decisions by Rosneft’s management and board of directors; the actions of
contractors; natural disasters and adverse weather conditions; changes in
public expectations and other changes to business conditions; wars and
acts of terrorism, cyber-attacks or sabotage; and other factors discussed
elsewhere in this report including under Risk factors (pages 51-55). In
addition to factors set forth elsewhere in this report, those set out 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 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.
acid and olefins and derivative value chains in 2014, Rosneft’s plans for its
refinery modernization programme, plans to expand ethanol production
capacity in Brazilian sugar cane mills, the expected level of production at
the Vivergo joint venture plant, the expected range for the annual charge of
Other businesses and corporate in 2014, plans regarding the reporting and
recording of losses of primary containment, the timing of the expected
delivery of new tankers, the impact of the additional regulation of GHG
emissions on BP’s business, plans to minimize air pollutants and emissions
at hydraulic fracturing sites, prospects for the UK temporary management
scheme in respect of Rhum and the resumption of operations thereat in the
future, plans for new investment including new drilling rigs in Alaska, plans
for oil sand development and a major seismic programme in Canada, plans
regarding deepwater blocks in offshore Brazil and Uruguay, the expected
production levels of the Angola LNG project, the expected completion of
farm-out agreements in Morocco, plans for a third train at the LNG plant in
Tangguh, prospects for Shah Deniz Stage 2 and the expected satisfaction
of conditions precedent to the planned purchase of an additional 3.3%
equity stake in Shah Deniz and the South Caucasus Pipeline from Statoil,
the expected amount of future payments from the disposal of interests in
certain North Sea fields, prospects for future developments at Mad Dog
Phase 2, plans regarding the timing of construction and production of the
Khazzan field in Oman, plans to drill four deepwater wells in the Ceduna
Sub Basin, the expected production life of the North West Shelf,
expectations regarding the naptha reformer at the Toledo refinery, plans to
increase investment in Africa, including in upgrades to refinery
infrastructure and the Pick n PayTM retail network, expectations regarding
future reserves booking, expectations of future undeveloped reserves
turnover time and volume, the anticipated future composition of the board
of directors, the timing of, cost of, source of payment and provision for
future remediation and restoration programmes and environmental
operating and capital expenditures, expectations regarding the impact of
various regulations upon BP’s business and expectations regarding greater
regulation and increased operating costs in the Gulf of Mexico in the future,
expectations regarding the issuance of a final policy for the materiality of
revenue and expenses under the Economic and Property Damages
Settlement Agreement by the claims administrator under such settlement,
and expectations regarding legal and trial proceedings, court decisions,
potential investigations and civil actions by regulators, government entities
and/or other entities or parties, and the risks associated with such
proceedings and BP’s intentions in respect thereof; (ii) certain statements
in Corporate governance (pages 59-80) and the Directors’ remuneration
report (pages 81-108) with regard to the anticipated future composition of
the board of directors, the board’s goals and plans stemming from the
board’s annual evaluation, plans regarding the timing of future audit
contract tendering, the expectation that BP will be in second place amongst
oil majors in respect of reserves replacement for the year ended 31
December 2013, the expected percentage of performance shares that will
vest based on 2013 outcomes, and plans and expectations with regard to
the remuneration, pensions and other benefits of executive directors,
including prospective scenarios for total remuneration opportunities for
executive directors in the future, changes in the metrics used to calculate
remuneration and changes to the limits of aggregate annual remuneration;
and (iii) certain statements in the Strategic report (pages 56-58), with regard
to future dividend and optional scrip dividend payments, including the
board’s plans for reviewing the dividend level in future quarters, future
capital expenditures and capital expenditure commitments, including
estimated levels of capital expenditure in 2014 and from 2015 to 2018,
taxation, intentions to maintain a significant liquidity buffer, future working
capital and cash flows, gearing and the net debt ratio, BP’s intention to
maintain a strong cash position, the expected effect on operating cash flow
of completion of Deepwater Horizon Oil Spill Trust fund payments and high-
margin projects coming onstream, expectations regarding taxes due upon
repatriation of cash into the UK, expectations regarding total capital
expenditure, and expected payments under contractual and commercial
commitments and purchase obligations; 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 or
may occur in the future and are outside the control of BP. Actual results
may differ materially from those expressed in such statements, depending
on a variety of factors, including the specific factors identified in the
discussions accompanying such forward-looking statements; the receipt of
relevant third party and/or regulatory approvals; the timing and level of
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Shareholder
information
274 Called-up share capital
274 Share prices and listings
274 Dividends
275 UK foreign exchange controls on dividends
275 Shareholder taxation information
277 Major shareholders
278 Purchases of equity securities by the issuer and
affiliated purchasers
278 Fees and charges payable by ADSs holders
279 Fees and payments made by the Depositary
to the issuer
279 Documents on display
280 Administration
280 Annual general meeting
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Called-up share capital
Details of the allotted, called-up and fully-paid share capital at
31 December 2013 are set out in Financial statements – Note 31.
At the AGM on 11 April 2013, authorization was given to the directors to
allot shares up to an aggregate nominal amount equal to $3,194 million.
Authority was also given to the directors to allot shares for cash and to
dispose of treasury shares, other than by way of rights issue, up to a
maximum of $240 million, without having to offer such shares to existing
shareholders. These authorities were given for the period until the next
AGM in 2014 or 11 July 2014, whichever is the earlier. These authorities
are renewed annually at the AGM.
Share prices and listings
Markets and market prices
The primary market for BP’s ordinary shares is the London Stock
Exchange (LSE). BP’s ordinary shares are a constituent element of the
Financial Times Stock Exchange 100 Index. BP’s ordinary shares are also
traded on the Frankfurt Stock Exchange in Germany.
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 electronically to the exchange by any firm that is a member of the
LSE, on behalf of a client or on behalf of itself acting as a principal. The
orders are then anonymously displayed in the order book. When there is a
match on a buy and a sell order, the trade is executed and automatically
reported to the LSE. Trading is continuous from 8.00 a.m. to 4.30 p.m. UK
time but, in the event of a 20% movement in the share price either way,
the LSE may impose a temporary halt in the trading of that company’s
shares in the order book to allow the market to re-establish equilibrium.
Dealings in ordinary shares may also take place between an investor and
a market-maker, via a member firm, outside the electronic order book.
In the US, BP’s securities are traded on the New York Stock Exchange
(NYSE) in the form of ADSs, for which JPMorgan Chase Bank, N.A. is the
depositary (the Depositary) and transfer agent. The Depositary’s principal
office is 1 Chase Manhattan Plaza, N.A., Floor 58, New York, NY 10005-
1401, US. Each ADS represents six ordinary shares. ADSs are listed on
the NYSE. ADSs are evidenced by American depositary receipts (ADRs),
which may be issued in either certificated or book entry form.
The following table sets forth, for the periods indicated, the highest and
lowest middle market quotations for BP’s ordinary shares and ADSs for
the periods shown. These are derived from the highest and lowest intra-
day sales prices as reported on the LSE and NYSE, respectively.
Year ended 31 December
2009
2010
2011
2012
2013
Year ended 31 December
2012: First quarter
Second quarter
Third quarter
Fourth quarter
2013: First quarter
Second quarter
Third quarter
Fourth quarter
2014: First quarter (to 18 February)
Month of
September 2013
October 2013
November 2013
December 2013
January 2014
February 2014 (to 18 February)
a One ADS is equivalent to six 25 cent ordinary shares.
Source: Thomson Reuters Datastream.
Pence
Dollars
Ordinary shares
American depositary sharesa
High
Low
High
Low
613.40
658.20
514.90
512.00
494.20
512.00
475.47
456.00
464.71
482.33
485.43
477.53
494.20
499.90
458.28
491.27
494.20
491.26
499.90
495.85
400.00
296.00
361.25
388.56
426.50
455.05
388.56
415.60
416.35
426.50
437.25
430.30
426.55
463.80
430.85
426.55
474.10
464.15
470.15
463.80
60.00
62.38
49.50
48.34
48.65
48.34
45.60
44.16
43.90
45.45
44.27
43.75
48.65
49.63
42.86
46.65
48.03
48.65
49.20
49.63
33.70
26.75
33.62
36.25
39.99
42.53
36.25
39.13
39.58
39.99
40.12
40.51
41.30
45.83
41.08
41.30
45.72
45.30
46.62
45.83
Market prices for the ordinary shares on the LSE and in after-hours
trading off the LSE, in each case while the NYSE is open, and the market
prices for ADSs on the NYSE, are closely related due to arbitrage among
the various markets, although differences may exist from time to time.
Dividends
BP’s current policy is to pay interim dividends on a quarterly basis on its
ordinary shares.
On 18 February 2014, 876,828,675.5 ADSs (equivalent to approximately
5,260,972,053 ordinary shares or some 28.51% of the total issued share
capital, excluding shares held in treasury) were outstanding and were
held by approximately 100,614 ADS holders. Of these, about 99,394 had
registered addresses in the US at that date. One of the registered holders
of ADSs represents some 868,478 underlying holders.
On 18 February 2014, there were approximately 279,391 ordinary
shareholders. Of these shareholders, around 1,574 had registered
addresses in the US and held a total of some 4,286,769 ordinary shares.
Since a number of the ordinary shares and ADSs were held by brokers
and other nominees, the number of holders in the US may not be
representative of the number of beneficial holders of their respective
country of residence.
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BP Annual Report and Form 20-F 2013
BP’s current policy is also to announce dividends for ordinary shares in
US dollars and state an equivalent sterling dividend. Dividends on BP
ordinary shares will be paid in sterling and on BP ADSs in US dollars. The
rate of exchange used to determine the sterling amount equivalent is the
average of the market exchange rates in London over the four business
days prior to the sterling equivalent announcement date. The directors may
choose to declare dividends in any currency provided that a sterling
equivalent is announced, but it is not the company’s intention to change its
current policy of announcing dividends on ordinary shares in US dollars.
Information regarding dividends announced and paid by the company on
ordinary shares and preference shares is provided in Financial statements
– Note 12.
A Scrip Dividend Programme (Scrip) was approved by shareholders in
2010 which enables BP ordinary shareholders and ADS holders to elect
to receive dividends by way of new fully paid BP ordinary shares (or
ADSs in the case of ADS holders) instead of cash. The operation of the
Scrip is always subject to the directors’ decision to make the Scrip offer
available in respect of any particular dividend. Should the directors decide
not to offer the Scrip in respect of any particular dividend, cash will be
paid automatically instead.
existing and proposed US Treasury regulations thereunder, published
rulings and court decisions, and the taxation laws of the UK, all as
currently in effect, as well as the income tax convention between the US
and the UK that entered into force on 31 March 2003 (the ‘Treaty’). These
laws are subject to change, possibly on a retroactive basis. This section is
further based in part on the representations of the Depositary and
assumes that each obligation in the Deposit Agreement and any related
agreement will be performed in accordance with its terms.
Future dividends will be dependent on future earnings, the financial
condition of the group, the Risk factors set out on page 51 and other
matters that may affect the business of the group set out in our strategy
on page 13 and in Liquidity and capital resources on page 56.
The following table shows dividends announced and paid by the
company per ADS for the past five years.
Dividends per ADSa
2009
2010
2011
2012
2013
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
March
58.91 57.50
84
June September December
51.07
51.02
84
84
84
Total
218.5
336
42
52.07
84
–
–
26.02 25.68
42
30.57 30.90
48
36.01 35.01
54
48
54
–
–
25.90
42
30.10
48
34.58
54
42
–
–
52.07
84
26.82 104.42
168
33.53 125.10
198
140.4
219
54
34.80
57
a Dividends announced and paid by the company on ordinary and preference shares are provided
in Financial statements – Note 12.
UK foreign exchange controls on dividends
There are currently no UK foreign exchange controls or restrictions on
remittances of dividends on the ordinary shares or on the conduct of the
company’s operations, other than restrictions applicable to certain
countries and persons subject to EU economic sanctions.
There are no limitations, either under the laws of the UK or under the
company’s Articles of Association, restricting the right of non-resident or
foreign owners to hold or vote BP ordinary or preference shares in the
company other than limitations that would generally apply to all of the
shareholders and limitations applicable to certain countries and persons
subject to EU economic sanctions.
Shareholder taxation information
This section describes the material US federal income tax and UK
taxation consequences of owning ordinary shares or ADSs to a US holder
who holds the ordinary shares or ADSs as capital assets for tax purposes.
It does not apply, however, interalia to members of special classes of
holders some of which may be subject to other rules, including: tax-
exempt entities, life insurance companies, dealers in securities, traders in
securities that elect a mark-to-market method of accounting for securities
holdings, investors liable for alternative minimum tax, holders that,
directly or indirectly, hold 10% or more of the company’s voting stock,
holders that hold the shares or ADSs as part of a straddle or a hedging or
conversion transaction, holders that purchase or sell the shares or ADSs
as part of a wash sale for US federal income tax purposes, or holders
whose functional currency is not the US dollar. In addition, if a
partnership holds the shares or ADSs, the US federal income tax
treatment of a partner will generally depend on the status of the partner
and the tax treatment of the partnership and may not be described fully
below.
A US holder is any beneficial owner of ordinary shares or ADSs that is for
US federal income tax purposes (i) a citizen or resident of the US, (ii) a US
domestic corporation, (iii) an estate whose income is subject to US
federal income taxation regardless of its source, or (iv) a trust if a US
court can exercise primary supervision over the trust’s administration and
one or more US persons are authorized to control all substantial decisions
of the trust.
This section is based on the tax laws of the United States, including the
Internal Revenue Code of 1986, as amended, its legislative history,
For purposes of the Treaty and the estate and gift tax Convention (the
‘Estate Tax Convention’) and for US federal income tax and UK taxation
purposes, a holder of ADRs evidencing ADSs will be treated as the
owner of the company’s ordinary shares represented by those ADRs.
Exchanges of ordinary shares for ADRs and ADRs for ordinary shares
generally will not be subject to US federal income tax or to UK taxation
other than stamp duty or stamp duty reserve tax, as described below.
Investors should consult their own tax adviser regarding the US federal,
state and local, UK and other tax consequences of owning and disposing
of ordinary shares and ADSs in their particular circumstances, and in
particular whether they are eligible for the benefits of the Treaty in
respect of their investment in the shares or ADSs.
Taxation of dividends
UK taxation
Under current UK taxation law, no withholding tax will be deducted from
dividends paid by the company, including dividends paid to US holders. A
shareholder that is a company resident for tax purposes in the UK or
trading in the UK through a permanent establishment generally will not
be taxable in the UK on a dividend it receives from the company. A
shareholder who is an individual resident for tax purposes in the UK is
subject to UK tax but entitled to a tax credit on cash dividends paid on
ordinary shares or ADSs of the company equal to one-ninth of the cash
dividend.
US federal income taxation
A US holder is subject to US federal income taxation on the gross
amount of any dividend paid by the company out of its current or
accumulated earnings and profits (as determined for US federal income
tax purposes). Dividends paid to a non-corporate US holder in taxable
years beginning after 2012 that constitute “qualified dividend income”
will be taxable to the holder at a maximum rate of 20%, provided that the
holder has a holding period in the ordinary shares or ADSs of more than
60 days during the 121-day period beginning 60 days before the ex-
dividend date and meets other holding period requirements. Dividends
paid by the company with respect to the ordinary shares or ADSs will
generally be qualified dividend income.
As noted above in UK taxation, a US holder will not be subject to UK
withholding tax. Accordingly, a US holder will include only the dividend
actually received from the company in gross income for US federal
income tax purposes, and the receipt of a dividend will not entitle the US
holder to a foreign tax credit.
For US federal income tax purposes, a dividend must be included in
income when the US holder, in the case of ordinary shares, or the
Depositary, in the case of ADSs, actually or constructively receives the
dividend and will not be eligible for the dividends-received deduction
generally allowed to US corporations in respect of dividends received
from other US corporations. Dividends will be income from sources
outside the US and generally will be ‘passive category income’ or, in the
case of certain US holders, ‘general category income’, each of which is
treated separately for purposes of computing a US holder’s foreign tax
credit limitation.
The amount of the dividend distribution on the ordinary shares that is paid
in pounds sterling will be the US dollar value of the pounds sterling
payments made, determined at the spot pounds sterling/ US dollar rate
on the date the dividend distribution is includible in income, regardless of
whether the payment is, in fact, converted into US dollars. Generally, any
gain or loss resulting from currency exchange fluctuations during the
period from the date the pounds sterling dividend payment is includible in
income to the date the payment is converted into US dollars will be
treated as ordinary income or loss and will not be eligible for the
preferential tax rate on qualified dividend income. The gain or loss
generally will be income or loss from sources within the US for foreign
tax credit limitation purposes.
BP Annual Report and Form 20-F 2013
275
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Distributions in excess of the company’s earnings and profits, as
determined for US federal income tax purposes, will be treated as a
return of capital to the extent of the US holder’s basis in the ordinary
shares or ADSs and thereafter as capital gain, subject to taxation as
described in Taxation of capital gains – US federal income taxation
section below.
In addition, the taxation of dividends may be subject to the rules for
passive foreign investment companies (PFIC), described below under
‘Taxation of capital gains – US federal income taxation’. Distributions
made by a PFIC do not constitute qualified dividend income and are not
eligible for the preferential tax rate applicable to such income.
Taxation of capital gains
UK taxation
A US holder may be liable for both UK and US tax in respect of a gain on
the disposal of ordinary shares or ADSs if the US holder is (i) a citizen of
the US resident or ordinarily resident in the UK, (ii) a US domestic
corporation resident in the UK by reason of its business being managed
or controlled in the UK or (iii) a citizen of the US or a corporation that
carries on a trade or profession or vocation in the UK through a branch or
agency or, in respect of corporations for accounting periods beginning on
or after 1 January 2003, through a permanent establishment, and that has
used, held, or acquired the ordinary shares or ADSs for the purposes of
such trade, profession or vocation of such branch, agency or permanent
establishment. However, such persons may be entitled to a tax credit
against their US federal income tax liability for the amount of UK capital
gains tax or UK corporation tax on chargeable gains (as the case may be)
that is paid in respect of such gain.
Under the Treaty, capital gains on dispositions of ordinary shares or ADSs
generally will be subject to tax only in the jurisdiction of residence of the
relevant holder as determined under both the laws of the UK and the US
and as required by the terms of the Treaty.
Under the Treaty, individuals who are residents of either the UK or the
US and who have been residents of the other jurisdiction (the US or the
UK, as the case may be) at any time during the six years immediately
preceding the relevant disposal of ordinary shares or ADSs may be
subject to tax with respect to capital gains arising from a disposition of
ordinary shares or ADSs of the company not only in the jurisdiction of
which the holder is resident at the time of the disposition but also in the
other jurisdiction.
US federal income taxation
A US holder who sells or otherwise disposes of ordinary shares or ADSs
will recognize a capital gain or loss for US federal income tax purposes
equal to the difference between the US dollar value of the amount
realized on the disposition and the US holder’s tax basis, determined in
US dollars, in the ordinary shares or ADSs. Any such capital gain or loss
generally will be long-term gain or loss, subject to tax at a preferential
rate for a non-corporate US holder, if the US holder’s holding period for
such ordinary shares or ADSs exceeds one year.
Gain or loss from the sale or other disposition of ordinary shares or ADSs
will generally be income or loss from sources within the US for foreign
tax credit limitation purposes. The deductibility of capital losses is subject
to limitations.
We do not believe that ordinary shares or ADSs will be treated as stock
of a passive foreign investment company, or PFIC, for US federal income
tax purposes, but this conclusion is a factual determination that is made
annually and thus is subject to change. If we are treated as a PFIC, unless
a US holder elects to be taxed annually on a mark-to-market basis with
respect to ordinary shares or ADSs, any gain realized on the sale or other
disposition of ordinary shares or ADSs would in general not be treated as
capital gain. Instead, a US holder would be treated as if he or she had
realized such gain rateably over the holding period for ordinary shares or
ADSs and would be taxed at the highest tax rate in effect for each such
year to which the gain was allocated, in addition to which an interest
charge in respect of the tax attributable to each such year would apply.
Certain ‘excess distributions’ would be similarly treated if we were
treated as a PFIC.
276
BP Annual Report and Form 20-F 2013
Additional tax considerations
Scrip Dividend Programme
The company has an optional Scrip Dividend Programme, wherein
holders of BP ordinary shares or ADSs may elect to receive any dividends
in the form of new fully paid ordinary shares or ADSs of the company
instead of cash. Please consult your tax adviser for the consequences to
you.
UK inheritance tax
The Estate Tax Convention applies to inheritance tax. ADSs held by an
individual who is domiciled for the purposes of the Estate Tax Convention
in the US and is not for the purposes of the Estate Tax Convention a
national of the UK will not be subject to UK inheritance tax on the
individual’s 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 used for the performance of
independent personal services. In the exceptional case where ADSs are
subject to both inheritance tax and US federal gift or estate tax, the
Estate Tax Convention generally provides for tax payable in the US to be
credited against tax payable in the UK or for tax paid in the UK to be
credited against tax payable in the US, 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 HM Revenue & Customs in the UK under existing law.
Provided that any instrument of transfer is not executed in the UK and
remains at all times outside the UK and the transfer does not relate to
any matter or thing done or to be done in the UK, no UK stamp duty is
payable on the acquisition or transfer of ADSs. Neither will an agreement
to transfer ADSs in the form of ADRs give rise to a liability to stamp duty
reserve tax.
Purchases of ordinary shares, as opposed to ADSs, through the CREST
system of paperless share transfers will be subject to stamp duty reserve
tax at 0.5%. The charge will arise as soon as there is an agreement for
the transfer of the shares (or, in the case of a conditional agreement,
when the condition is fulfilled). The stamp duty reserve tax will apply to
agreements to transfer ordinary shares even if the agreement is made
outside the UK between two non-residents. Purchases of ordinary shares
outside the CREST system are subject either to stamp duty at a rate of
£5 per £1,000 (or part, unless the stamp duty is less than £5, when no
stamp duty is charged), or stamp duty reserve tax at 0.5%. Stamp duty
and stamp duty reserve tax are generally the liability of the purchaser.
A subsequent transfer of ordinary shares to the Depositary’s nominee
will give rise to further stamp duty at the rate of £1.50 per £100 (or part)
or stamp duty reserve tax at the rate of 1.5% of the value of the ordinary
shares at the time of the transfer. For ADR holders electing to receive
ADSs instead of cash, after the 2012 first quarter dividend payment HM
Revenue & Customs no longer seeks to impose 1.5% stamp duty
reserve tax on issues of UK shares and securities to non-EU clearance
services and depositary receipt systems.
US Medicare Tax
For taxable years beginning after December 31, 2012, a US holder that is
an individual or estate, or a trust that does not fall into a special class of
trusts that is exempt from such tax, will be subject to an additional 3.8%
“Medicare tax” on the lesser of (1) the US holder’s “net investment
income” for the relevant taxable year and (2) the excess of the US
holder’s modified adjusted gross income for the taxable year over a
certain threshold (which in the case of individuals will be $125,000,
$200,000 or $250,000, depending on the individual’s circumstances). A
US holder’s net investment income will generally include its dividend
income and its net gains from the sale or other disposition of ordinary
shares or ADSs. If you are a US holder that is an individual, estate or
trust, you are urged to consult your tax adviser regarding the applicability
of the Medicare tax to your income and gains in respect of your
investment in ordinary shares or ADSs.
a Includes JPMorgan Chase Bank, N.A. holding 28.70% of the total ordinary issued share capital
(excluding shares held in treasury) as the approved depositary for ADSs, a breakdown of which is
shown in the table below.
Smith & Williamson Investment
Management Ltd.
Major shareholders
The disclosure of certain major and significant shareholdings in the share
capital of the company is governed by the Companies Act 2006, the UK
Financial Conduct Authority’s Disclosure and Transparency Rules (DTR)
and the US Securities Exchange Act of 1934.
Register of members holding BP ordinary shares as at
31 December 2013
Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000a
Totals
Number of ordinary
shareholders
58,190
101,442
112,294
10,920
823
678
Percentage of total
ordinary shareholders
20.46
35.68
39.49
3.84
0.29
0.24
Percentage of total
ordinary share capital
excluding shares
held in treasury
0.02
0.29
1.82
1.18
1.67
95.02
284,347
100.00
100.00
Register of holders of American depositary shares (ADSs) as at
31 December 2013a
Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000b
Totals
Number of
ADS holders
58,281
27,376
14,699
809
10
1
101,176
Percentage of total
ADS holders
57.60
27.06
14.53
0.80
0.01
0.00
Percentage of total
ADSs
0.36
1.47
4.34
1.51
0.16
92.16
100.00
100.00
a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 868,478 underlying shareholders.
As at 31 December 2013, there were also 1,510 preference
shareholders. Preference shareholders represented 0.45% and ordinary
shareholders represented 99.55% of the total issued nominal share
capital of the company (excluding shares held in treasury) as at that date.
In accordance with DTR 5, we have received notification that as at
31 December 2013 BlackRock, Inc held 5.61%, Legal & General Group
plc held 3.50% and The Capital Group Companies, Inc held 3.37% of the
voting rights of the issued share capital of the company. As at
18 February 2014 BlackRock, Inc held 5.73%, Legal & General Group plc
held 3.51% and The Capital Group Companies, Inc. held 3.35% of the
voting rights of the issued share capital of the company.
Under the US Securities Exchange Act of 1934 BP has received
notification of the following interests as at 18 February 2014:
Holder
JPMorgan Chase Bank N.A., depositary
for ADSs, through its nominee
Guaranty Nominees Limited
BlackRock, Inc.
Percentage
of ordinary
share capital
excluding
shares held
in treasury
Holding of
ordinary shares
5,260,972,053
1,057,431,913
28.51
5.73
The company’s major shareholders do not have different voting rights.
The company has also been notified of the following interests in
preference shares as at 18 February 2014:
Holder
The National Farmers Union Mutual
Insurance Society
M & G Investment Management Ltd.
Smith & Williamson Investment
Management Ltd.
Duncan Lawrie Ltd.
Holder
The National Farmers Union Mutual
Insurance Society
M & G Investment Management Ltd.
Holding of 8%
cumulative first
preference shares
Percentage
of class
945,000
528,150
409,200
364,876
13.07
7.30
5.66
5.04
Holding of 9%
cumulative second
preference shares
Percentage
of class
987,000
644,450
352,000
338,000
18.03
11.77
6.43
6.18
Royal London Asset Management Ltd.
Lazard Asset Management Limited disposed of its interests in 374,000
8% cumulative first preference shares and 404,500 9% cumulative
second preference shares during 2011.
Gartmore Investment Management Limited disposed of its interest in
394,538 8% cumulative first preference shares and 500,000 9%
cumulative second preference shares during 2010.
In accordance with DTR 5.8.12, The Capital Group of Companies, Inc.
notified the company on 24 September 2012 that due to their group
reorganization their holdings would not be reported separately but as a
combined holdings thereby taking their interest in shares above the 3%
threshold as of 1 September 2012.
As at 18 February 2014, the total preference shares in issue comprised
only 0.45% of the company’s total issued nominal share capital
(excluding shares held in treasury), the rest being ordinary shares.
No changes in interests in the share capital of the company have been
notified to the company in accordance with DTR 5 between
31 December 2013 and 18 February 2014.
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BP Annual Report and Form 20-F 2013
277
Purchases of equity securities by the issuer and affiliated purchasers
On 22 March 2013 BP announced the start of a share repurchase, or buyback, programme (the buyback programme). The buyback programme is
expected to return up to $8 billion to BP shareholders. As at 18 February 2014 the total number of ordinary shares repurchased under the buyback
programme since 22 March 2013 was 947,930,354 at a cost of $7,065 million including transaction costs. The following table provides details of this
share repurchase activity under the buyback programme as well as details of ordinary share purchases made by the Employee Share Ownership Plans
(ESOPs) and other purchases of ordinary shares and ADSs made to satisfy the requirements of certain employee share-based payment plans.
Number
of shares
purchased
by ESOPs or for
certain employee
share-based
payment plansb
Number
of shares
purchased as
part of publicly
announced
programmesc
Maximum
approximate
dollar value
of shares
that may yet
be purchased
under the
programme
$ million
Total number
of shares
purchaseda
Average price
paid per share
$
2013
January
February
March 22 – March 28
April 2 – April 30
May 1 – May 31
June 3 – June 28
July 1 – July 31
August 1 – August 31
September 2 – September 30
October 1 – October 31
November 1 – November 29
December 2 – December 31
2014
January 2 – January 31
February 3 to February 18
–
–
21,400,000
102,573,190
91,671,000
74,649,000
66,536,585
57,395,332
64,540,000
92,100,761
129,680,000
99,933,273
162,240,000
34,836,545
–
–
7.04
6.94
7.25
7.14
7.07
6.90
7.08
7.22
7.87
7.83
8.09
7.92
–
–
–
–
–
21,400,000
1,800,000 100,773,190
91,671,000
74,649,000
66,536,585
47,150,000
62,680,000
91,080,761
– 129,680,000
67,233,273
–
–
–
10,245,332
1,860,000
1,020,000
32,700,000
2,000,000
– 162,240,000
32,836,545
–
–
7,849
7,150
6,485
5,952
5,482
5,155
4,711
4,053
3,032
2,507
1,194
934
a All share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions.
b Transactions represent the purchase of ordinary shares by ESOPs and other purchases of ordinary shares and ADSs made to satisfy requirements of certain employee share-based payment plans.
c At the AGMs on 12 April 2012 and 11 April 2013, authorization was given in each case to repurchase up to 1.9 billion ordinary shares in the period to the next AGM in 2013 and 2014, respectively or
12 July 2013 and 11 July 2014, respectively, being the latest dates by which an AGM must be held for the relevant year. This authorization is renewed annually at the AGM. All shares were purchased
for cancellation to reduce BP’s issued share capital. The total number of ordinary shares purchased during 2013 under the buyback programme was 752,853,809 at a cost of $5,493 million (including
transaction costs) representing 4.04% of BP’s issued share capital excluding shares held in treasury on 31 December 2013.
Fees and charges payable by ADSs holders
The Depositary collects fees for delivery and surrender of ADSs directly from investors depositing shares or surrendering ADSs for the purpose of
withdrawal or from intermediaries acting for them. The Depositary collects fees for making distributions to investors by deducting those fees from the
amounts distributed or by selling a portion of the distributable property to pay the fees.
The charges of the Depositary payable by investors are as follows:
Type of service
Depositing or substituting the underlying
shares
Selling or exercising rights
Withdrawing an underlying share
Expenses of the Depositary
Depositary actions
Issuance of ADSs against the deposit of shares, including
deposits and issuances in respect of:
• Share distributions, stock splits, rights, merger.
• Exchange of securities or other transactions or event or
other distribution affecting the ADSs or deposited
securities.
Distribution or sale of securities, the fee being in an amount
equal to the fee for the execution and delivery of ADSs that
would have been charged as a result of the deposit of such
securities.
Acceptance of ADSs surrendered for withdrawal of deposited
securities.
Expenses incurred on behalf of holders in connection with:
• Stock transfer or other taxes and governmental charges.
• Cable, telex, electronic and facsimile transmission, delivery.
• Transfer or registration fees, if applicable, for the
registration of transfers of underlying shares.
• Expenses of the Depositary in connection with the
conversion of foreign currency into US dollars (which are
paid out of such foreign currency).
Fee
$5.00 per 100 ADSs (or portion
thereof) evidenced by the new ADSs
delivered.
$5.00 per 100 ADSs (or portion
thereof).
$5.00 for each 100 ADSs (or portion
thereof) evidenced by the ADSs
surrendered.
Expenses payable at the sole
discretion of the Depositary by billing
holders or by deducting charges from
one or more cash dividends or other
cash distributions.
278
BP Annual Report and Form 20-F 2013
Fees and payments made by the Depositary
to the issuer
The Depositary has agreed to reimburse certain company expenses
related to the company’s ADS programme and incurred by the company
in connection with the ADS programme arising during the year ended
31 December 2013. The Depositary reimbursed to the company, or paid
amounts on the company’s behalf to third parties, or waived its fees and
expenses, of $2,815,205.43 for the year ended 31 December 2013.
The table below sets out the types of expenses that the Depositary has
agreed to reimburse and the fees it has agreed to waive for standard
costs associated with the administration of the ADS programme relating
to the year ended 31 December 2013. The Depositary has also paid
certain expenses directly to third parties on behalf of the company.
Category of expense reimbursed,
waived or paid directly to third parties
NYSE listing fees reimbursed
Service fees and out of pocket expenses
waiveda
Broker fees reimbursedb
Other third-party mailing costs reimbursedc
Total
Amount reimbursed, waived or paid
directly to third parties for
the year ended 31 December 2013
$420,168
$1,428,022.6
$858,306.07
$108,708.76
$2,815,205.43
a Includes fees in relation to transfer agent costs and costs of the BP Scrip Dividend Programme
operated by JPMorgan Chase Bank, N.A.
b Broker reimbursements are fees payable to Broadridge for the distribution of hard copy material
to ADR beneficial holders in the Depository Trust Company. Corporate materials include
information related to shareholders’ meetings and related voting instructions. These fees are
SEC approved.
c Payment of fees to Precision IR for proxy solicitation and investor support.
Under certain circumstances, including removal of the Depositary or
termination of the ADR programme by the company, the company is
required to repay the Depositary amounts reimbursed and/or expenses
paid to or on behalf of the company during the 12-month period prior to
notice of removal or termination.
Documents on display
BP Annual Report and Form 20-F 2013 and BP Strategic Report 2013 are
also available online at bp.com/annualreport. Shareholders may obtain a
hard copy of BP’s complete audited financial statements, free of charge,
by contacting BP Distribution Services at +44 (0)870 241 3269 or via an
email request addressed to bpdistributionservices@bp.com or from
Precision IR at +1 888 301 2505 or via an email request addressed to
bpreports@precisionir.com if in the US and Canada.
The company is subject to the information requirements of the US
Securities Exchange Act of 1934 applicable to foreign private issuers. In
accordance with these requirements, the company files its Annual Report
on Form 20-F and other related documents with the SEC. It is possible to
read and copy documents that have been filed with the SEC at the SEC’s
public reference room located at 100 F Street NE, Washington, DC
20549, US. You may also call the SEC at +1 800-SEC-0330. In addition,
BP’s SEC filings are available to the public at the SEC’s website. BP
discloses on its website at bp.com/NYSEcorporategovernancerules, and
in this report (see Corporate governance practices (Form 20-F Item 16G)
on page 110) significant ways (if any) in which its corporate governance
practices differ from those mandated for US companies under NYSE
listing standards.
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BP Annual Report and Form 20-F 2013
279
Annual general meeting
The 2014 AGM will be held on Thursday, 10 April 2014 at 11.30 a.m. at
ExCeL London, One Western Gateway, Royal Victoria Dock, London
E16 1XL. A separate notice convening the meeting is distributed to
shareholders, which includes an explanation of the items of business to
be considered at the meeting.
All resolutions for which notice has been given, will be decided on a
poll. Ernst & Young LLP have expressed their willingness to continue in
office as auditors and a resolution for their reappointment is included in
the Notice of BP Annual General Meeting 2014.
Administration
If you have any queries about the administration of shareholdings, such
as change of address, change of ownership, dividend payments or the
Scrip Dividend Programme or to change the way you receive your
company documents (such as the BP Annual Report and Form 20-F,
BP Strategic Report and Notice of BP Annual General Meeting) please
contact the BP Registrar or the BP ADS Depositary.
Ordinary and preference shareholders
The BP Registrar
Capita Asset Services
The Registry, 34 Beckenham Road
Beckenham, Kent BR3 4TU, UK
Freephone in UK 0800 701107
From outside the UK +44 (0)20 3170 3678
Textphone 0871 664 0532; fax +44 (0)1484 601512
Please note that any numbers quoted with the prefix 0871 will be
charged at 10p per minute from a BT landline. Other network providers’
costs may vary and calls from mobiles will be considerably higher.
ADS holders
JPMorgan Chase Bank, N.A. PO Box 64504
St Paul, MN 55164-0504, US
Toll-free in US and Canada +1 877 638 5672
From outside the US and Canada +1 651 306 4383
The Directors’ report on pages 59-80, 109-114, 116, 200-223 and 235-280 was approved by the board and signed on its behalf by David J Jackson,
Company Secretary on 6 March 2014.
BP p.l.c.
Registered in England and Wales No. 102498
280
BP Annual Report and Form 20-F 2013
Signatures
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned
to sign this annual report on its behalf.
BP p.l.c.
(Registrant)
/s/ David J Jackson
Company Secretary
6 March 2014
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BP Annual Report and Form 20-F 2013
281
Cross reference to Form 20-F
Item 1.
Item 2.
Item 3.
Item 4.
Item 4A.
Item 5.
Item 6.
Item 7.
Item 8.
Item 9.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16A.
Item 16B.
Item 16C.
Item 16D.
Item 16E.
Item 16F.
Item 16G.
Item 17.
Item 18.
Item 19.
A.
B.
C.
D.
Identity of Directors, Senior Management and Advisors
Offer Statistics and Expected Timetable
Key Information
Selected financial data
Capitalization and indebtedness
Reasons for the offer and use of proceeds
Risk factors
Information on the Company
A.
History and development of the company
Business overview
B.
C. Organizational structure
D.
Property, plants and equipment
Unresolved Staff Comments
Operating and Financial Review and Prospects
A. Operating results
B.
Liquidity and capital resources
C.
D.
E.
F.
G.
A.
B.
C.
D.
E.
Research and development, patent and licenses
Trend information
Off-balance sheet arrangements
Tabular disclosure of contractual commitments
Safe harbor
Directors, Senior Management and Employees
Directors and senior management
Compensation
Board practices
Employees
Share ownership
Major Shareholders and Related Party Transactions
A. Major shareholders
B.
C.
Related party transactions
Interests of experts and counsel
Financial Information
Consolidated statements and other financial information
Significant changes
The Offer and Listing
A.
B.
A. Offer and listing details
B.
Plan of distribution
C. Markets
D.
E.
F.
Selling shareholders
Dilution
Expenses of the issue
Additional Information
Share capital
A.
B. Memorandum and articles of association
C. Material contracts
Exchange controls
D.
Taxation
E.
Dividends and paying agents
F.
Statements by experts
G.
Documents on display
H.
Subsidiary information
I.
Quantitative and Qualitative Disclosures about Market Risk
Description of securities other than equity securities
A.
Debt Securities
B. Warrants and Rights
C. Other Securities
D.
American Depositary Shares
Defaults, Dividend Arrearages and Delinquencies
Material Modifications to the Rights of Security Holders and Use of Proceeds
Controls and Procedures
Audit Committee Financial Expert
Code of Ethics
Principal Accountant Fees and Services
Exemptions from the Listing Standards for Audit Committees
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
Change in Registrant’s Certifying Accountant
Corporate governance
Financial Statements
Financial Statements
Exhibits
282
BP Annual Report and Form 20-F 2013
Page
n/a
n/a
236
n/a
n/a
51-55
ii, 2-40, 56-58, 236, 239-243
2-5, 10-19, 23-58, 149-154, 239-257, 269-271
193
25-37, 191, 222-223, 239-251, 268
None
23-25, 27-28, 31-33, 36-37, 40, 56-58, 126, 252
56-58, 75, 132-133, 161, 166-170, 172-176,
191
16-17, 35, 37, 154
10-11, 22-37
57, 252-253
57, 252-253
n/a
60-68
82-108, 158, 178-181, 190
61-65, 71, 74-80, 90, 105, 108
47-48, 189-190
48, 91, 93-95, 189-190
277
163-166, 268
n/a
56, 120-199, 257-268, 274-275
None
274
n/a
274
n/a
n/a
n/a
n/a
112-114
268
275
275-276
n/a
n/a
279
193
166-170, 172-176
n/a
n/a
n/a
278-279
None
None
111, 121
74
111
111, 192
n/a
278
None
110-111
n/a
120-199
269
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financial and operating performance, sustainability performance
and also on global energy trends and projections.
Annual Report and
Form 20-F 2013
Details of our financial
and operating performance
in print or online.
Published in March.
bp.com/annualreport
Sustainability Review 2013
A summary of our
sustainability reporting with
additional information online.
Published in March.
bp.com/sustainability
Strategic Report 2013
A summary of our financial
and operating performance
in print or online.
Published in March.
bp.com/annualreport
Financial and Operating
Information 2009-2013
Five-year financial and
operating data in PDF
or Excel format.
Published in April.
bp.com/financialandoperating
Energy Outlook 2035
Projections for world energy
markets, considering the
potential evolution of global
economy, population, policy
and technology.
Published in January.
bp.com/energyoutlook
Statistical Review of
World Energy 2014
An objective review of key
global energy trends.
Published in June.
bp.com/statisticalreview
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Acknowledgements
Design
Typesetting RR Donnelley
Printing
Salterbaxter
Pureprint Group Limited, UK,
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This document has been printed using vegetable inks.
© BP p.l.c. 2014
Photography Shahin Abasaliyev, Pankaj Anand,
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Andy McAuslan, Marc Morrison,
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