BP Annual Report 2014 | Quarterlytics

FY2014 Annual Report · BP

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Annual Report and
Form 20-F 2014

bp.com/annualreport

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.

BP proposition

We prioritize value over volume
by actively managing a high-value
upstream and downstream portfolio
and investing only where we can
apply the distinctive strengths,
capabilities and technologies that we
have built up over decades.

Our objective is to create shareholder
value by growing sustainable free
cash ﬂow over the long term. Our
disciplined approach enables us to
grow distributions to our shareholders
over time.

See bp.com/bpproposition

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
across the world. We employ around
85,000 people.

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, North and
South America, Australasia, Asia
and Africa.

a On the basis of market capitalization, proved reserves
and production.

Front cover imagery
An operations technician and process engineer
perform safety checks on the Atlantis platform
in the Gulf of Mexico. The region is an important
part of our upstream portfolio and Atlantis is one
of four BP-operated platforms there. The Mardi
Gras pipeline that stretches across 450 miles of
the Gulf moves oil and gas production to
onshore facilities from these platforms.

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
the corporate reporting team. Details are on
the back cover.

BP Annual Report and Form 20-F 2014

BP in 2014

We have reshaped and
repositioned the business
for the future, with a clear
strategy that has put us on
course to grow value for
shareholders.

Information about this report

1 Strategic report
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 markets in 2014
21
Group performance

51 Corporate governance
52
56
58
59
61
62
63
63

Board of directors
Executive team
Governance overview
How the board works
Board effectiveness
Shareholder engagement
International advisory board
Internal control revised guidance
for directors (Turnbull)
Audit committee

24
29
33
35
36
39
46
48

69
71
71
72

Upstream
Downstream
Rosneft
Other businesses and corporate
Gulf of Mexico oil spill
Corporate responsibility
Our management of risk
Risk factors

Safety, ethics and environment
assurance committee
Gulf of Mexico committee
Nomination committee
Chairman’s committee
Directors’ remuneration report

★ Glossary

Words with this symbol★ are deﬁned
in the glossary on page 252.

89 Financial statements
90
91

Statement of directors’ responsibilities
Consolidated ﬁnancial statements
of the BP group

100 Notes on ﬁnancial statements

167

197

Supplementary information on oil and
natural gas (unaudited)
Parent company ﬁnancial statements
of BP p.l.c.

207 Additional disclosures
208 Selected ﬁnancial information
211 Liquidity and capital resources
213 Upstream analysis by region
217 Downstream plant capacity
219 Oil and gas disclosures for the group
225 Environmental expenditure
225 Regulation of the group’s business
228 Legal proceedings
238
239 Material contracts

International trade sanctions

239 Property, plant and equipment
239 Related-party transactions
239 Corporate governance practices
240 Code of ethics
240 Controls and procedures
241 Principal accountants’ fees and services
241 Directors’ report information
241

Disclosures required under Listing
Rule 9.8.4.R
241 Cautionary statement

243 Shareholder information
244 Share prices and listings
244 Dividends
245 UK foreign exchange controls on dividends
245 Shareholder taxation information
247 Major shareholders
247 Annual general meeting
247 Memorandum and Articles of Association
250

Purchases of equity securities by the
issuer and afﬁliated purchasers

251 Fees and charges payable by

251

ADSs holders
Fees and payments made by
the Depositary to the issuer

251 Documents on display
252 Shareholding administration
252 Exhibits
252 Abbreviations, glossary and trade marks

256 Signatures
257 Cross reference to Form 20-F

BP Annual Report and Form 20-F 2014

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Information about this report

Cautionary statement
This document should be read in
conjunction with the cautionary
statement on page 241.

Frequently used abbreviations, terms
and BP and third-party trade marks are
described on page 252.

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 2014. A cross reference to Form 20-F requirements
is included on page 257.

This document contains the Strategic report on pages 1-50 and the inside cover (Who we are section)
and the Directors’ report on pages 51-71, 90, 167-196 and 207-255. 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
72-88. The consolidated ﬁnancial statements of the group are on pages 89-166 and the corresponding
reports of the auditor are on pages 91-95. The parent company ﬁnancial statements of BP p.l.c. are on
pages 197-206.

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 2014 and BP Strategic Report 2014 (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 2014 or BP Strategic
Report 2014 (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
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 244 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 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.

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.
London Stock Exchange symbol ‘BP.’

BP Annual Report and Form 20-F 2014

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Strategic
report

An overview of the key
activities, events and results
in 2014, together with
commentary on BP’s
performance 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

14
Strategy in action
16 Distinctive capabilities

18 Our key performance indicators

20 Our markets in 2014

21 Group performance

21
22

10-point plan performance
Financial and operating performance

24 Upstream

29 Downstream

33 Rosneft

35 Other businesses and corporate

36 Gulf of Mexico oil spill

39 Corporate responsibility

39 Safety
42
44

Environment and society
Employees

46 Our management of risk

48 Risk factors

BP Annual Report and Form 20-F 2014

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 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.

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.

Upstream

Our Upstream segment manages exploration,
development and production activities.

See KPIs page 18.

See Upstream page 24.

$3.8bn

proﬁt attributable to
BP shareholders
2013: $23.5bn

$32.8bn

operating cash
ﬂow★
2013: $21.1bn

Upstream proved
reservesb (mmboe)

3.2

million barrels of oil
equivalent per daya
2013: 3.2mmboe/d

16.7%

gearing (net
debt ratio)★
2013: 16.2%

tier 1 process
safety events★
2013: 20

a See footnote e on page 23.

BP Annual Report and Form 20-F 2014

Liquids
1. Subsidiaries★
2. Equity-accounted entities
Total

4,092
717
4,809

Natural gas
3. Subsidiaries
4. Equity-accounted entities
Total

5,603
409
6,012

$8.9bn

replacement cost proﬁt
before interest and tax
2013: $16.7bn

2.1

million barrels of oil
equivalent per dayb
2013: 2.3mmboe/d

47,000km2

new exploration access
2013: 43,000km2

upstream major project★
start-ups
2013: 3 major projects

b Excludes BP’s share of Rosneft.
See Rosneft on page 33.

All data provided on pages 2-5 is at or for the
year ended 31 December 2014.

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

Downstream Our Downstream segment operates

hydrocarbon value chains covering three
main businesses – fuels, lubricants and
petrochemicals.

Biofuels

See Downstream page 29.

Operating capital
employed c

1. Fuels
2. Lubricants
3. Petrochemicals

$32.8bn
$1.5bn
$4.6bn

$3.7bn

replacement cost proﬁt
before interest and tax
2013: $2.9bn

1.7

million barrels of oil reﬁned
per day
2013: 1.8mmb/d

14.0

41%

million tonnes of petrochemicals
produced in the year
2013: 13.9mmte

of our lubricants sales were
premium grades
2013: 40%

c This is a non-GAAP measure, but is
provided for investors as it is used by
BP management to make ﬁnancial
and strategic decisions. See page 210.

Investing
in renewable energy

We develop and invest in biofuels and operate
a wind business.

Shareholder value

$5.9bn

dividends paid

6.0%

ordinary shareholders
annual dividend yield★

6.2%

ADS shareholders
annual dividend yield★

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

BP around the world

BP has operations in almost
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
2014 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 2014.

Upstream see page 24.

Downstream

Reﬁnery.
Petrochemicals site(s).

Downstream see page 29.

Alternative energies

Operational assets.
Technology assets.

Alternative energies see page 35.

BP group headcount by region
(including 14,400 service station staff)

1. Europe
2. US and Canada
3. Asia Paciﬁc
4. South and Central

33,400
18,800
15,800

America
5. Middle East and
North Africa
6. Sub-Saharan
Africa
Total

8,000

6,100

2,400
84,500

BP Annual Report and Form 20-F 2014

Gulf of Mexico

Fuels

We have been exploring in the deepwater Gulf
of Mexico for more than 25 years and are one of
the region’s largest investors. With 10 rigs in
operation, we are engaged in a range of
activities including exploration, appraisal and
development and production.

Our fuels business is made up of regionally
based integrated fuels value chains. These
include reﬁneries and fuels marketing
businesses together with global oil supply
and trading activities. We supply fuel and
related convenience services to consumers
at around 17,200 BP-branded retail sites and
market our products in over 50 countries.

Lower 48

Alternative energies

We launched the US Lower 48 as a separate BP
upstream business in January 2015 with its own
governance, processes and systems to manage
our onshore oil and gas assets in the US
(excluding Alaska). See page 24 for further
information.

Our participation in alternative energies
is focused on biofuels and wind. Our
interests include three sugar cane mills in
Brazil, a joint venture★ bioethanol facility in
the UK and 16 wind farms in the US.

North Sea

Azerbaijan

Rosneft

We received our ﬁrst UK North Sea exploration
licence 50 years ago. Since then, we’ve
developed activities that cover 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 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 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 10 trillion cubic
feet of gas. Rosneft’s downstream
operations include interests in 14 reﬁneries.
See page 33 for further information.

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Angola

Lubricants

Petrochemicals

Angola is Africa’s second largest oil producer.
We have interests in nine major deepwater
blocks with a total acreage of more than
32,600km2. Our Cravo, Lirio, Orquidea
and Violet (CLOV) project is planned
to develop signiﬁcant resources across its
development areas.

We market lubricants and related products
and services in approximately 75 countries
through direct sales or locally approved
distributors. We leverage brand, technology
and relationships, focusing our resources on
core and growing markets.

Petrochemicals produces products across 16
manufacturing sites and sells them to
customers in more than 40 countries.
Approximately 48% of petrochemicals
capacity is in Asia, 27% in the US and 25% in
Europe.

★ Defined on page 252.

BP Annual Report and Form 20-F 2014

Chairman’s letter

In the present environment,
returns to shareholders remain
a key priority.

Carl-Henric Svanberg

Dear fellow shareholder,
We started 2014 with conﬁdence in the overall development of the world and a feeling of
progress in most of the world’s economies after several challenging years. However, the
year ended with signiﬁcant uncertainties. BP operates in a geopolitical environment that
has become more turbulent and the price of oil has signiﬁcantly declined, returning to a
pattern of volatility not seen for several years. The industry must adapt rapidly. Even before
the recent volatility, we have taken measures to streamline and reshape BP. We believe
we are well positioned to meet the challenges of the coming years.

In 2011, we set out our 10-point plan with clear goals that we have delivered over the last
three years. This is a signiﬁcant achievement for Bob Dudley and his team. It marks a
major step in refocusing the company after the tragic events of 2010 when 11 people lost
their lives in the Deepwater Horizon accident – something we must never forget. Our
strategic progress has to be tempered by the ﬁnding of gross negligence in the Clean
Water Act litigation in the US, which we strongly disagree with and are appealing.

Strategy
Completing the 10-point plan does not mean that our work is done. Far from it. The board
continues to be deeply involved in discussing and shaping our strategy – with its clear
priorities, quality portfolio and distinctive capabilities.

We successfully sold assets at a time of higher oil prices and are now going through a
rapid cost adjustment to address this new landscape and improve our underlying business
performance. We are refocusing our approach to producing hydrocarbons in the US Lower
48 and we are resetting our operations across the entire business. This is all taking place
without compromising on safety. Our recent strategic partnership with Chevron in the Gulf
of Mexico demonstrates what we mean by value over volume through a new ownership
and operating model. Our goals are to make investment choices that play to our strengths,
increase sustainable free cash ﬂow and grow our distributions to shareholders.

We began a number of these initiatives earlier in 2014, putting us ahead of the current oil
price pressures. These strategic actions will continue and more will be necessary as we
respond to short-term imperatives. We aim to ensure that BP builds on its distinctive
strengths in 2015 and beyond.

Shareholder distributions
The improved performance over the year and progress in strategic delivery has led to the
board’s decision to increase the dividend. During 2014, the board reviewed the dividend
twice and each time raised it by 2.6%. These increases are part of our strategy to grow
distributions. During 2014 BP completed its $8-billion share buyback programme using
proceeds from the sale of our interest in TNK-BP. Shares worth a further $2.3 billion were
also bought back in the year. In the present environment, returns to shareholders remain a
key priority.

10-year dividend history
UK (pence per ordinary share)

36.42

29.39

21.10 21.00

19.15

23.40 23.85

20.85

17.40

8.68

US (cents per ADS)

330 336

254

230

209

400

300

200

100

219

234

198

168

One ADS represents six 25 cent ordinary shares.

BP Annual Report and Form 20-F 2014

Board performance
For information about the board and its
committees see page 51.

Remuneration
For information about our directors’
remuneration see page 72.

Top: Members of BP’s safety, ethics and
environmental assurance committee (SEEAC)
in Azerbaijan.

Bottom: Cynthia Carroll attends a brieﬁng during
a visit to Brazil with SEEAC.

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Oversight
The board has continued to maintain oversight of performance, risk and ﬁnancial efﬁciency
and kept a constant scrutiny on safety. Each year we review and monitor the group level
risks through our own work and our committees, who carry out the majority of the work,
leaving the board free to address strategic issues.

There are, however, longer-term issues on which we also have to focus, such as carbon
and its role in climate change. It is clear that it is for governments and regulators to set the
boundary conditions to address these issues and we will develop our business within their
framework. For example, we already factor a price for carbon into our project evaluation.
We recognize that we need to play our part in informing this debate and we do this
through our projections for future world energy markets in the BP Energy Outlook 2035.
Throughout, we must remain alert to developments that may alter the world in which we
operate. The board is recommending that shareholders support the resolution at the
annual general meeting seeking greater transparency of reporting in this important area.

Governance and succession
The board regularly considers how it operates and the appropriate composition and mix
around the board table – both to respond to today’s challenges and BP’s future strategic
direction. Antony Burgmans, the current chair of the remuneration committee, will stand
down as a director in 2016. In anticipation of his departure, Dame Ann Dowling will take
over the chair of that committee during 2015. We have also considered the chairs and
membership of all other committees. In 2012, upon Andrew Shilston joining the board and
being appointed the senior independent director, we announced that Antony Burgmans
would retain a role as an internal sounding board. This role will cease after the annual
general meeting. Andrew will join the remuneration and nomination committees.

I would like to welcome Alan Boeckmann who joined the board as a non-executive director
in July. Alan brings deep experience of contractor management, procurement and project
delivery in our industry following his career in Fluor Corporation. Alan will be joining the
remuneration committee after the annual general meeting. Our longest serving director,
Iain Conn, left the company in December to become chief executive of Centrica after an
almost 30-year career with BP, spanning different businesses and regions. George David
will retire from the board at our AGM in April. My fellow directors and I thank both Iain and
George for their huge contributions and work on behalf of the board.

I would also like to thank Bob Dudley, his team, my board colleagues and all our
employees for all that they have done. Finally, my thanks go to you, our shareholders, for
the support you have shown us during the year.

Carl-Henric Svanberg
Chairman
3 March 2015

BP Annual Report and Form 20-F 2014

Group chief executive’s letter

Our efforts over the past three
years have helped prepare us
to face the new oil price
challenge with resilience.

Bob Dudley

Dear fellow shareholder,
The year 2014 was pivotal for BP. Despite the increasingly challenging business
environment, we completed the 10-point plan we had set out in 2011 to make BP a safer,
stronger, better performing business. Compared with three years ago, we have reduced
safety-related incidents, delivered strong operating efﬁciencies and met our target to
increase operating cash ﬂow by more than 50%.

Our performance is important, not only because we achieved our targets, but because we
did what we said we would do. I know how important it is to shareholders that we
continue delivering on our commitments.

2014 was a turbulent year – for BP and the industry. Oil prices fell dramatically and
returned to their familiar pattern of volatility, after several exceptional years in which they
remained above $100 per barrel. I expect these lower and more volatile prices to continue
through 2015 and likely longer. We are now resetting the business to deliver value in this
new context, scaling back capital spending and reducing costs, while always maintaining
our primary focus on safety.

Our efforts over the past three years have helped prepare us to face the new oil price
challenge with resilience. We have reshaped and strengthened our portfolio through a
divestment programme, reduced our costs to reﬂect a smaller footprint and articulated a
strategy based on clear priorities, a quality portfolio and distinctive capabilities.

Clear priorities
Safe and reliable operations will always be our ﬁrst priority. While we have made real
progress in the past three years, sadly there were three workforce fatalities in 2014, in
accidents at a German reﬁnery, a UK North Sea platform and an Indonesian
petrochemicals plant. Our thoughts are with the families and friends of those who died and
we will implement the lessons from these tragic events.

Since 2011 we have reduced the number of tier 1 and tier 2 process safety events – the
most serious incidents, leaks, spills and other releases. After making very good progress in
2013, we saw a higher number of such incidents in 2014. We are renewing our efforts to
ensure conformance with our operating management system, allied to the right personal
behaviours, taking great care in everything we do.

We clearly demonstrated capital discipline through 2014, restricting spending to around
$23 billion, relative to guidance of $24-25 billion. We also saw good project execution as
we met our plans to bring onstream seven start-up projects.

Quality portfolio
We continue to actively manage our portfolio, focusing on assets which play to our
strengths and divesting assets that no longer ﬁt our strategy. In both our Upstream and
Downstream businesses, we are taking a rigorous approach to capital allocation and
concentrating on efﬁciency and competitiveness in our activities. Making the right
investment choices is of the highest priority.

94.9%

2014 reﬁning availability.

90%

Upstream BP-operated plant efﬁciency .

BP Annual Report and Form 20-F 2014

Delivery of our 10-point plan
For details of our performance against the
plan see page 21.

Our strategy
For more on our strategic priorities and
longer-term objectives see page 13.

Our key performance indicators
Find out how we measure our
performance on page 18.

Top: Bob Dudley at the World Petroleum
Congress in Moscow.

Bottom: Bob Dudley congratulates winners at the
Helios awards – where teams from across the
world are recognized for their contributions to
building a safer, stronger BP in line with our
values.

We grew our exploration position during the year, with new access in ﬁve areas and
hydrocarbon discoveries in the Gulf of Mexico, Brazil, the North Sea, Egypt and Angola.
We began operating our onshore oil and gas operations in the ‘Lower 48’ states of the US
as a separate business in January 2015. In the Downstream, we improved performance
from fuels marketing, increased our capacity to reﬁne heavy crude and shale oil in the US,
maintained the focus on premium brands and growth markets in lubricants and reviewed
the petrochemicals business to increase its earnings potential.

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Having completed our $38-billion divestment programme ahead of schedule, we
committed to make a further $10 billion of divestments by the end of 2015. By the end of
2014 we had agreed transactions amounting to $4.7 billion.

Distinctive capabilities
BP’s distinctive capabilities of advanced technology, proven expertise and strong
relationships underpin our progress. We have invested over the years to be a specialist in
several key areas of technology. For example, in 2014 we started using robots to test
enhanced oil recovery options, helping us reduce time to production.

The expertise of our people is central to our progress so developing our employees in
critical areas is an ongoing activity. For example, we run specialist academies dedicated to
global wells expertise and safety and operational risk, as well as other areas.

Strong relationships remain vital – with communities, governments, partners, suppliers,
staff and shareholders. The rapid progress made on the Southern Corridor project, which
will pipe natural gas from the Caspian Sea to markets as far away as Italy, is just one
example. With our partners, we have already awarded more than $9 billion of contracts to
make, transport and install facilities.

A challenging environment
In 2015 we entered a very different landscape from that in which we began last year. The
lower oil price presents formidable challenges for the industry. In these volatile times, BP
continues to drive capital discipline by constraining the total level of capital spend in any
one year, taking account of the opportunities available and the ﬂexibility of our balance
sheet.

Meanwhile, we continue to manage issues speciﬁc to BP. The legal proceedings in the US
associated with the Deepwater Horizon accident and oil spill continue. In the ﬁrst trial
phase the judge issued a ﬁnding of gross negligence and wilful misconduct. We strongly
disagree with these ﬁndings and have appealed. In the second phase the court found no
gross negligence in our source control efforts and ruled that 3.19 million barrels of oil were
discharged into the Gulf of Mexico. We have also appealed this ruling. The penalty phase
trial ﬁnished in February, with the ruling to come at a later date. In all of the proceedings,
we are seeking fair and just outcomes while protecting the best interests of our
shareholders.

Our investment in Rosneft, funded from the proceeds of our sale of TNK-BP in 2013,
continues to attract attention. Our approach is to comply with all relevant sanctions and
otherwise to maintain our distinctive, long-term investment and relationship with Rosneft
in a country that holds some of the world’s largest oil and gas resources. There is strong
interdependence between Russia and its trading partners, and I believe that over time
such commercial links tend to ease tensions rather than exacerbate them.

The BP of 2015 is a robust and resilient business, a global team that has been through
some of the most difﬁcult times an organization can face and emerged stronger, safer and
better than before.

Bob Dudley
Group chief executive
3 March 2015

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

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.

Affordability – fossil fuels can become more
difﬁcult to access as the easiest and highest
quality resources are depleted ﬁrst, and many
non-fossil fuel resources remain costly to
produce at scale.

Continued advances in technology and
energy-industry productivity are required to
deliver affordable, sustainable and secure
energy. The shale gas revolution demonstrates
the potential impact of such developments.

Effective policy
We believe governments must set a stable
framework to encourage private sector
investment and to help consumers choose
wisely. This includes secure access for the
exploration and development of energy
resources; mutual beneﬁts for resource owners
and development partners; and an appropriate
legal and regulatory environment with an
economy-wide price on carbon.

Energy efﬁciency
Greater efﬁciency helps with affordability –
because less energy is needed; with security
– because it reduces dependence on imports;
and with sustainability – because it reduces
emissions. Innovation can play a key role in
improving technology, bringing down cost and
increasing efﬁciency. In transport, for example,
we believe energy-efﬁcient technologies and
biofuels could offer the most cost-effective
pathway to a secure, lower-carbon future.

Our markets in 2014
See page 20 for information on oil and gas
prices in 2014.

How BP is preparing for the
near-term outlook
(cid:116)(cid:1) We exercise capital discipline by

constraining the total level of capital spend
and the number of projects sanctioned each
year.

(cid:116)(cid:1) We sanction upstream projects at $80a per
barrel, while testing projects for resilience at
$60a per barrel.

(cid:116)(cid:1) Our balance sheet gives us resilience to

withstand a period of low prices.
(cid:116)(cid:1) With a third of our production from

production-sharing agreements and an
increasing portfolio of high-quality gas
projects, we are reducing our vulnerability
to global oil price movements.

(cid:116)(cid:1) We continue to right-size the group’s cost
base to align with BP’s smaller footprint.

a In real terms based to 2012.

For further detail on the projections of future
energy trends contained in this section,
please refer to BP Energy Outlook 2035.

BP Annual Report and Form 20-F 2014

Near-term outlook
Oil prices, after around four years of averaging
around $100 per barrel, have fallen by more
than 50%. This reﬂects strong production
growth in the US, increases in global supply
elsewhere and weaker global demand. Prices
weakened further following OPEC’s decision in
November to maintain production.

Prices are expected to remain low through the
near term, at least. And while we anticipate
supply chain deﬂation by 2016 and beyond, as
industry costs follow oil prices with a lag, this
will be a tough period of intense change for the
industry as it adapts to this new reality.

Long-term outlook
Population and economic growth are the main
drivers of global energy demand. The world’s
population is projected to increase by 1.6 billion
from 2013 to 2035, and the world economy is
likely to more than double in size over the same
period. Improvements to energy efﬁciency,
further stimulated by new climate policies and a
shift towards less energy-intensive activities in
fast-growing economies will restrain the growth
of energy consumption. But we still expect
world demand for energy to increase by as much
as 37% between 2013 and 2035, with 96% of
the growth in non-OECD countries.

Energy resources are available to meet this
growing demand, but developing these
resources presents a number of challenges:

Sustainability – action is needed to limit carbon
dioxide (CO2) and other greenhouse gases
emitted through fossil fuel use.

Supply security – more than 60% of the world’s
known reserves of natural gas are in just ﬁve
countries, and more than 80% of global oil
reserves are located in nine countries, often
distant from the hubs of energy consumption.

Energy consumption by region
(billion tonnes of oil equivalent)

Other

India

China

OECD

12
10

1965

2000

2035

Source: BP Energy Outlook 2035.

Energy consumption by fuel
(billion tonnes of oil equivalent)

Renewables*
Hydro

Nuclear
Coal

Gas
Oil

12
10

1965
*Includes biofuels.
Source: BP Energy Outlook 2035.

2000

2035

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
scenarioa), oil and gas would still make up 49%
of the energy mix in 2030 and 43% in 2040.

We expect oil to remain the dominant source for
transport fuels, accounting for almost 90% of
demand in 2035.

Natural gas, in particular, is likely to play an
increasing role in meeting global energy
demand. By 2035 gas is expected to provide
26% of global energy, matching the share of
coal. Natural gas produces about half as much
CO2 as coal per unit of power generated, so
increasing the share of gas versus coal helps to
restrain greenhouse gas emissions. Shale gas
has already had a signiﬁcant impact on US gas
prices and demand, and is expected to
contribute 47% of the growth in global natural
gas supplies between 2013 and 2035.

New sources of hydrocarbons may be 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.

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Renewables
Renewables will play an increasingly important
role in addressing the long-term challenges of
energy security and climate change. They are
already the fastest-growing energy source, but
are starting from a low base. By 2035, we
estimate renewable energy, excluding large-
scale hydroelectricity, is likely to meet around
8% of total global energy demand.

Temporary policy support is needed to help
commercialize lower-carbon options and
technologies, but they will ultimately need to
become commercially self-sustaining, supported
only by a carbon price.

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.

a From World Energy Outlook 2014. © OECD/International
Energy Agency 2014, page 607. The IEA’s 450 policy 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.

Our strategy
Find out how BP can help meet energy
demand for years to come on page 13.

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. Also
available in Excel and video format.

We provide a long-term technology view on
future trends and their potential impact on the
energy system. This helps assess lessons learned
from technology’s evolution and how it may
shape our future energy choices.

See bp.com/energyoutlook

See bp.com/energy-technology-future

BP Annual Report and Form 20-F 2014

11
11

Our business model

We aim to create value for our investors and beneﬁts for
the communities and societies where we operate.

A process engineer monitors instrument readings
at our Castellón reﬁnery in Spain. The reﬁnery has
the ﬂexibility to run sour, heavy and highly acidic
crudes.

In Trinidad & Tobago we are the largest
hydrocarbon producer, accounting for about 50%
of the nation’s oil and gas.

We believe 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. By supplying energy, we support
economic development and help to improve
quality of life for millions of people. Our activities
also generate jobs, investment, infrastructure
and revenues for governments and local
communities.

Our business model spans everything from
exploration to marketing. We have a diverse
integrated portfolio that is focused and adaptable
to prevailing conditions. 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.

Every stage of the hydrocarbon value chain
offers opportunities for us to create value,
through both the successful execution of
activities that are core to our industry, and the

application of our own distinctive strengths and
capabilities in performing those activities.

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 where 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.

Illustrated business model
For an at a glance overview of our
business model see page 2.

Our businesses
For more information on our upstream
and downstream business models, see
pages 24 and 29 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.

Developing and
extracting

Transporting
and trading

Manufacturing and
marketing

When we ﬁnd hydrocarbon resources,
we aim to create value by progressing
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 rail.
Using our trading and supply skills
and knowledge, we buy and sell at
each stage of 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.

BP Annual Report and Form 20-F 2014

Our strategy

Our goal is to be a focused oil and gas company that
delivers value over volume.

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An operator commissions a steam system at the
Whiting reﬁnery in the US.

Technical operations onboard our ﬂoating
production, storage and ofﬂoading vessel in
Angola.

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 work to develop and maintain
strong relationships – with governments,
partners, civil society and others – to enhance
our operations in almost 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 how we are delivering our strategy
on page 14.

Our key performance indicators
See how we measure our progress
on page 18.

Risks
Find out how we manage the risks to our
strategy on page 46.

We prioritize value over volume by actively
managing a high-value upstream and
downstream portfolio and investing only where
we can apply the distinctive strengths,
capabilities and technologies we have built up
over decades.

Our objective is to create shareholder value by
growing sustainable free cash ﬂow
over the long term. Our disciplined approach
enables us to grow distributions to our
shareholders over time.

We are pursuing our strategy by setting clear
priorities, actively managing a quality portfolio
and employing our distinctive capabilities.

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 in support of growth
in operating cash from our businesses,
disciplined allocation of capital and ﬁnancial
resilience.

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 deep water, giant ﬁelds and selected
gas value chains. And, in our downstream
businesses, we plan to leverage our newly
upgraded assets, customer relationships and
technology to grow operating cash ﬂow.

Our portfolio of projects and operations is
focused where we believe we can generate the
most value, and not necessarily the most
volume, through our production.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Our strategy in action

Delivering energy
Delivering energy
to the world
to the world

Safe, reliable and
compliant operations

Clear priorities

Competitive
project
execution

Disciplined
ﬁnancial
choices

Grow our
exploration
position

Focus on
high-value
upstream assets

Quality portfolio

Build high-quality
downstream businesses

Safe, reliable and
compliant operations

Disciplined ﬁnancial
choices

Competitive project
execution

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.

How we measure
For deﬁnitions of how we measure
our performance, see Our key
performance indicators on page 18.

BP Annual Report and Form 20-F 2014

How we deliver

How we measure

Strategy in action in 2014

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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,
gearing, total shareholder
return, underlying
replacement cost proﬁt
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.

Reserves
replacement ratio.

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 years to come.

Production.

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.

Reﬁning availability.

Creating shareholder value by generating
Creating shareholder value by generating
sustainable free cash ﬂow
sustainable free cash ﬂow

Running reliably
Running operations safely
is Air BP’s ﬁrst priority.
See page 40.

tier 1 process
safety events.

Increasing value
An alternative solution to
increase long-term value.

See page 21.

$32.8bn

operating cash ﬂow.

Unlocking hidden
resources
Using our advanced technology
and exploration experience
to access gas in Oman.
See page 27.

major project start-ups
in Upstream.

Extending the life of
the North Sea
Our latest discovery
demonstrates the basin’s
ongoing potential.
See page 28.

Committing to the
future
Increasing production in
the Gulf of Mexico.

See page 25.

Driving success
Our retail partnership with
Marks & Spencer is driving
sales growth.

See page 31.

63%

reserves
replacement ratio.a

3.2

million barrels of oil
equivalent per day.a

94.9%

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 aim to form enduring partnerships in the
countries in which we operate, building strong
relationships with governments, customers,
partners, 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
Our talented people help to drive our business
forward. They apply their diverse skills and
expertise to deliver complex projects across all
areas of our business.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

a On a combined basis of subsidiaries and equity-accounted entities.

Our distinctive capabilities

Advanced technology

We use technology to ﬁnd and produce more oil
and gas, improve our processes for conversion
into valuable products and develop lower-carbon
energy solutions.

We aim to build strategic relationships with
universities for research, recruitment, policy
insights and education. Our long-term research
programmes around the world are exploring
areas from reservoir ﬂuid ﬂow to novel lubricant
additives. For example through the BP
International Centre for Advanced Materials
almost 70 researchers are working on around 20
projects to advance the understanding and use
of materials across a variety of energy and
industrial applications.

The ﬁrst priority for all our technology teams is
improving the safety and integrity of our
operations.

Our upstream technology programmes 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
improving the efﬁciency of unconventional oil
and gas production.

We focus our downstream technology
programmes on improving the performance of
our reﬁneries and petrochemicals plants and on
creating high quality, energy efﬁcient, cleaner
products.

We employ scientists and technologists at
seven major technology centres in the US, UK
and Germany. In 2014 we invested $663 million
in research and development (2013 $707 million,
2012 $674 million).

See bp.com/technology

1 2 Seismic imaging
We use our imaging expertise to increase the
productivity and quality of the data we capture
on land and offshore. We conducted one of our
largest-ever onshore seismic surveys in 2014
covering 2,800km2 at the Khazzan ﬁeld in Oman.

4 Enhanced oil recovery (EOR)
BP delivers more light oil EOR production than
any other international oil company. In 2014 we
introduced the world’s ﬁrst automated robot for
testing EOR technologies, shortening the time
we need to spend on development and trials
before bringing them to ﬁeld.

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. In 2014 we established a
digital centre of expertise for technologies to
analyse data, improve decision making and
enhance efﬁciency.

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
Our global graduate and
postgraduate
programmes recruited
670 people in 2014.

Internal promotion
We promoted 4,880
employees including
524 group and senior
level leaders.

Group leaders
Our group leaders have
an average of 20 years’
experience in BP.

External hires
We hired 8,640 people
including 97 group and
senior level leaders.

Developing the talent pipeline

Employees

For more information about our
people and values see page 44.

At our Wayne technology center in New Jersey
chemists research new formulations to improve
lubricant performance.

Proven expertise

We aim to maintain a skilled workforce to deliver our
strategy and meet our commitments to investors,
partners and the wider world. We compete for the
best people within the energy sector and other
industries.

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.

We have a bias towards building capability within the
organization, complemented by selective external
recruitment where necessary, and invest in all our
employees’ development to build a sustainable
talent pipeline.

Our approach to professional development and
training helps build individual capabilities, reducing a
potential skills gap. We believe our shared values help
everyone at BP to contribute to their full potential.

BP Annual Report and Form 20-F 2014

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6 Corrosion prevention
Wireless Permasense® systems provide
frequent and on-demand corrosion monitoring
by detecting unexpected changes in the wall
thickness of pipes. Developed in collaboration
with Imperial College, London, they are used
across all our reﬁneries to monitor the integrity
of critical assets.

8 Fuels
Our gasoline and diesel additive Ultimate in a
Bottle, launched in China in 2014, helps clean
and protect engines, enhance performance for
diesel in cold weather and reduce emissions to
improve air quality.

10 Biofuels
We are developing biobutanol in conjunction
with DuPont. This second-generation biofuel
can be blended into gasoline in greater
proportions and is more compatible than
ethanol with the infrastructure used for
existing fuel supplies.

7 Lubricants
We focus on providing energy-efﬁcient and
high-performance products to customers. In 2014
we launched Castrol EDGE with Titanium Fluid
Strength Technology, which changes the way
engine oil behaves under extreme pressure,
reducing friction by up to 15%.

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

We work closely with governments, national oil
companies and other resource holders to build
long-lasting relationships that are crucial to the
success of our business.

We place enormous importance on acting
responsibly and meeting our obligations as we
know from experience that trust can be lost. We
work on big and complex projects with partners
ranging from other oil companies 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, engage with our stakeholders and
help create shared value.

Universities
and research
institutions

National
and international
oil companies

Banks and
providers of
ﬁnance

Intern

l r e lation

Governments
and
regulators

Industry
bodies

Customers

Communities

Suppliers,
partners and
contractors

BP Annual Report and Form 20-F 2014

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 periodically
review our metrics and test their
relevance to our strategy. 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
We have replaced the RC proﬁt
per ordinary share KPI to underlying
RC proﬁt per ordinary share. This is
one of the measures used by
management to evaluate BP’s
operational performance and is also
used as a performance measure for
executive directors’ remuneration.
All other KPIs remain the same.

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.

Directors’ remuneration
See how our performance
impacted 2014 pay on
page 72.

Key

KPIs used to measure

progress against our strategy.

KPIs used to determine 2014

and 2015 remuneration.

Underlying RC proﬁt and gearing
are non-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.

Underlying RC proﬁt
per ordinary share (cents)

Operating cash ﬂow

($ billion)

Gearing (net debt ratio)

(%)

107.39

111.97

89.70

70.92

66.00

125

100

22.2

20.5

21.1

13.6

32.8

21.2

20.4

18.7

16.2

16.7

2011

2012

2013

2010

2014
Underlying RC proﬁt is a useful measure
for investors because it is one of the
proﬁtability measures BP management
uses to assess performance. It assists
management in understanding the
underlying trends in operational
performance on a comparable
year-on-year basis.

It reﬂects the replacement cost of
inventories sold in the period and is
arrived at by excluding inventory holding
gains and losses from proﬁt or loss.
Adjustments are also made for
non-operating items and fair value
accounting effects . The IFRS
equivalent can be found on page 208.

2014 performance The decrease in
underlying RC proﬁt per ordinary share
for the year compared with 2013 was
mainly due to a lower proﬁt in Upstream
and lower earnings from Rosneft.

2014

2012

2013

2010

2011
Operating cash ﬂow is net cash ﬂow
provided by operating activities, as
reported in 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.

2014 performance Operating cash ﬂow
was higher in 2014 in line with delivery
of the 10-point plan.

2012

2010

2013
2011
Our gearing (net debt ratio) shows
investors how signiﬁcant net debt is
relative to equity from shareholders in
funding BP’s operations.

2014

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. For the nearest equivalent
measure on an IFRS basis and for further
information see Financial statements –
Note 25.

2014 performance Gearing at the end
of 2014 was 16.7%, up 0.5% on 2013
and within our target band of 10-20%.

Reﬁning availability (%)

Reported recordable injury
frequencya

Loss of primary containmenta

95.0

94.8

95.3
95.3

94.9

Employees
4
8
.
0

1.00

Contractors

0.75

0.50

0.25

5
2
.
0

3
4
.
0

1
4
.
1 0
3
.
0

6
2
.
0

6
3
.

5 0
2
.
0

7
2
.
0

4
3
.
0

500

400

300

200

100

418

361

292

261

286

2010

2011

2012

2013

2014

2010

2011

2012

2013

2014

2010

2011

2012

2013

2014

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
downtime.

Reﬁning availability is an important
indicator of the operational performance
of our Downstream businesses.

2014 performance Reﬁning availability
decreased by 0.4% from 2013 to 94.9%
reﬂecting the completion of the Whiting
reﬁnery modernization project and
ramp-up of operations.

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.

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.

The measure gives an indication of the
personal safety of our workforce.

2014 performance Our workforce RIF,
which includes employees and
contractors combined, is 0.31, level with
2013. While this is encouraging, we have
seen an increase in our day away from
work case frequency (see page 39).
We are reviewing our personal safety
programmes and continue to focus our
efforts on safety.

By tracking these losses we can monitor
the safety and efﬁciency of our
operations as well as our progress in
making improvements.

2014 performance The increase in 2014
reporting reﬂects the introduction of
enhanced automated monitoring for
many remote sites in our Lower 48
business. Using a like-for-like approach
with previous years’ reporting, our 2014
loss of primary containment ﬁgure is 246.

BP Annual Report and Form 20-F 2014

Total shareholder return (%)

Reserves replacement ratio (%)

Major project delivery

Production (mboe/d)

ADS basis

Ordinary share basis

-20

)
1
.
4
2
(

)
4
.
1
2
(

5
.
2

0
.
3

5
.
4

6
.
2

7
.
4
1

0
.
4
1

)
5
.
6
1
(

)
6
.
1
1
(

140

120

100

129

106

103

4,000

3,822

3,800

3,600

3,400

3,200

3,454

3,331

3,230

3,151

S
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a
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i
c
r
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p
o
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t

2010

2011

2012

2013

2014

Total shareholder return (TSR)
represents the change in value of a
BP shareholding over a calendar year.
It assumes that dividends are reinvested
to purchase additional shares at the
closing price on the ex-dividend date.
We are committed to maintaining a
progressive and sustainable dividend
policy.

2014 performance TSR decreased during
the year, primarily as a result of a fall in
the BP share price, partly offset by two
dividend per share increases in 2014.

2011

2012

2013

2010

2014
Proved reserves replacement ratio is the
extent to which the year’s production has
been replaced by proved reserves added
to our reserve base.

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.

This measure helps to demonstrate our
success in accessing, exploring and
extracting resources.

2014 performance The reserves
replacement ratio reﬂects lower reserves
bookings as a result of fewer ﬁnal
investment decisions in 2014 and
revisions of previous estimates.

2011

2012

2013

2010

2014
Major projects are deﬁned as those with
a BP net investment of at least $250
million, or considered to be of strategic
importance to BP, or of a high degree
of complexity.

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.

2014 performance In total we delivered
seven major project start-ups in
Upstream.

2014

2012

2013

2010

2011
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.

2014 performance BP’s total reported
production including our Upstream
segment and Rosneft was 2.4% lower
than in 2013. This reduction reﬂected
the Abu Dhabi onshore concession
expiry and divestments, partially offset
by increased production from
higher-margin areas and higher
production in Rosneft in 2014 compared
to the aggregate production in Rosneft
and TNK-BP in 2013.

Tier 1 process safety events a

Greenhouse gas emissionsb
(million tonnes of CO2 equivalent)

Group priorities
engagemente (%)

Diversity and inclusione (%)

100

64.9

61.8

59.8

50.3

48.6

100

Data not
collected

Women

Non UK/US

0
2

9
1

7
1

2
2

8
1

9
1

4
1

5
1

2010

2011

2012

2013

2014

2010

2011

2012

2013

2014

2010

2011

2012

2013

2014

2010

2011

2012

2013

2014

We report tier 1 process safety events,
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.

2014 performance The number of tier 1
process safety events has decreased
substantially since 2010. We take a
long-term view on process safety
indicators because the full beneﬁt of the
decisions and actions in this area is not
always immediate.

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 provide data on greenhouse gas
(GHG) emissions material to our business
on a carbon dioxide-equivalent basis. This
includes CO2 and methane for direct
emissions.c Our GHG KPI 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.d Emissions data for Rosneft can
be found on its website.

2014 performance The decrease in our
GHG emissions is primarily due to the
sale of our Carson and Texas City
reﬁneries in the US as part of our
divestment programme.

b The reported 2013 ﬁgure of 49.2MteCO2e
has been amended to 50.3MteCO2e.
c For indirect emissions data see page 42.
d For our emissions on an operational control
basis see page 42.

We track how engaged our employees
are with our strategic priorities for
building long-term value. This is derived
from survey questions about
perceptions of BP as a company and
how it is managed in terms of leadership
and standards.

2014 performance The 2014 survey
found that employees remain clear
about safety procedures, standards and
requirements that apply to them and
that pride in working at BP has increased
steadily since 2011. Understanding and
support of BP’s strategy is strong at
senior levels, but needs further
communication and engagement across
the organization.

e Relates to BP employees.

Each year we report the percentage of
women and individuals from countries
other than the UK and the US among
BP’s group leaders. This helps us track
progress in building a diverse and
well-balanced leadership team.

2014 performance The percentage of our
group leaders who are women or
non-UK/US has remained steady this
year. We remain committed to our aim
that women will represent at least 25%
of our group leaders by 2020.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Our markets in 2014

A snapshot of the global energy market in 2014, as oil prices
return to a pattern of volatility.

A mechanical technician works on the ﬂoating,
production, storage and ofﬂoading vessel in
Angola’s ultra-deep water.

‘Pipe alley’ at Cooper River petrochemicals plant.
The site is one of the world’s largest producers of
PTA, a raw material primarily used to manufacture
polyester and plastic bottles.

Crude oil prices (quarterly average)

Brent dated

$120

$100

$80

$60

e
r
r
a
b

r
e
p

s
r
a

l
l

o
d
S
U

Oil and gas pricing

For more on upstream markets in 2014
see page 25.

Natural gas
Global price differentials in 2014 continued to
narrow. US gas prices moved up, while
European and Asian spot LNG prices weakened.
The Henry Hub index increased from $3.7 per
million British thermal units (mmBtu) in 2013 to
$4.4 in 2014.

Spot LNG prices in Europe and Asia fell with
rising global LNG supplies and weak demand
growth. New LNG projects in Papua New
Guinea and Australia, and recovering supplies in
Africa have added to the market in 2014.

Moderating demand and milder weather
reduced the UK National Balancing Point hub
price to an average of 50 pence per therm in
2014 (2013 68). The Japanese spot price fell to
an average of $13.9/mmBtu in 2014 (2013 $16.6).

In 2013 growth in natural gas consumption
slowed to a below-average rate and broad
differentials between regional gas prices
continued, although they did not widen further
as US gas prices recovered from their 2012
lows. Global LNG supply expanded in 2013,
following a contraction in supply in 2012. But the
LNG market remained tight, as strong demand
continued in Asia from economic growth and
nuclear power outages, and in Latin America
due to the effect of a drought on hydroelectric
production.

Economic growth has remained relatively weak
globally, and was weaker in the emerging
non-OECD economies than recent years. Within
the OECD, the US and UK performed best –
growing at around their medium-term potential
– while Japan and the Eurozone have
underperformed against their potential.

Oil
Crude oil prices, as demonstrated by the
industry benchmark of dated Brent, averaged
$98.95 per barrel in 2014. For the period from
2010 to mid-2014, oil prices followed a pattern of
relative stability at around $110 a barrel. Prices
averaged $109 during the ﬁrst half of 2014, but
fell sharply by more than 50% since June in the
face of continued strong growth of light, sweet
oil production in the US, and weak global
consumption growth. Brent prices ended the
year near $55.

Amid continued high oil prices for much of the
year and weak economic growth in emerging
economies, global oil consumption increased by
a below-average 0.6 million barrels per day
(mmb/d) for the year (0.7%).a The growth in
consumption was greatly exceeded by record
growth in non-OPEC production (2.0 mmb/d),
mainly by continued strong growth in US output.
OPEC crude oil production fell slightly due to
renewed outages in Libya. On balance,
production signiﬁcantly exceeded consumption,
resulting in a large increase in OECD commercial
oil inventories.

In 2013 global oil consumption grew by roughly
1.4 million barrels per day (1.4%), signiﬁcantly
more than the increase in global production
(0.6%).b Non-OPEC production accounted for all
of the net global increase, driven by robust US
growth.

Reﬁning margins

For more on downstream markets in 2014
see page 30.

a From Oil Market Report 10 February 2015©,
OECD/IEA 2015, page 4.
b BP Statistical Review of World Energy June 2014.

BP Annual Report and Form 20-F 2014

Group performance

A summary of our group ﬁnancial and operating performance.

S
t
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10-point plan performance
In 2014 we completed our three-year 10-point plan, established in 2011, to help stabilize BP and restore trust and value in response to the tragic
Deepwater Horizon accident in 2010. Here we report on our performance in delivering the plan over the period.

Relentless focus on safety
We reduced tier 1 process safety events★ and loss of primary
containment (LOPC) by 62% and 21% respectively over the plan
period. However, in 2014 there were eight more tier 1 events and
25 more LOPC incidents than 2013. Safety remains our primary
focus and we continue to focus our efforts on it.

Play to our strengths
We accessed almost 158,000 km2 exploration acres, made 13 new
discoveries and drilled a total of 44 exploration wells (2014 18).

Stronger and more focused
We have reshaped our portfolio to have a set of high-value
deepwater assets, gas value chains, giant ﬁelds, and
a high-quality downstream business. We sold around half of
our upstream installations and pipelines, and one third of
our wells – while retaining roughly 90% of our proved reserves
and production.

Simpler and more standardized
We implemented standardized global systems and
processes and established global functional organizations to
conduct all BP-operated drilling and wells activity and
manage the development of our major projects★.

More visibility and transparency to value
We provide downstream results by fuels, petrochemicals and
lubricants, and report earnings from Rosneft as a separate
operating segment.

Active portfolio management
We completed our $38-billion divestment programme ahead of
schedule and plan for a further $10 billion of divestments before
the end of 2015, with $4.7 billion of sales already agreed.

New upstream projects onstream with unit cash margins★
double the 2011 average
We started up 15 major upstream projects, of which 13 are in the
four higher-margin areas (Angola, Azerbaijan, Gulf of Mexico and
North Sea). Average forecast unit cash margins (2014-23) for the 15
projects at $100/bbl oil price were more than double the 2011
upstream segment average.

Generate around 50% more in operating cash ﬂow★ by 2014
versus 2011a
We reported $32.8 billion of operating cash ﬂow in 2014 (averaged
oil price of $98.95/bbl, averaged Henry Hub gas price of
$4.43/mmBtu) – exceeding our target of around 50% increase on
2011.

Half of incremental operating cash for reinvestment – half
for other purposes including distributions
The dividend paid in 2014 increased by 39% since 2011, and we
carried out $10.3 billion of share buybacks since March 2013,
when a share repurchase programme was announced.

Strong balance sheet
Our gearing★ stayed within our target range of 10-20%,
decreasing from 20.4% in 2011 to 16.7% at the end of 2014.

Increasing value

Delivering our goal of value over volume means tough decisions can be
necessary to make the best ﬁnancial choices for BP.

An important part of our portfolio in the Gulf of Mexico is the
deepwater Atlantis ﬁeld which is early in its life cycle. To increase
recovery from the ﬁeld, we had planned to install new subsea
infrastructure, requiring a long and expensive construction period.
When reassessing our ﬁeld development plan we concluded that our
approach would not generate the most value from the ﬁeld, so we
decided to look for an alternative solution.

By using our existing subsea facilities to safely drill future wells, rather
than building new infrastructure, we aim to deliver just as much value
to BP as originally planned, while requiring millions less in capital
expenditure and reducing corresponding risk and demand for
resources. The change in plan could signiﬁcantly increase the Atlantis
ﬁeld’s capital efﬁciency and cash ﬂow over the next ﬁve years.

This focus on capital allocation discipline is being rigorously applied on
all of our ﬁelds around the world.

We only select the best options that maximize value.

a Assumed an oil price of $100/bbl and a Henry Hub gas price of $5/mmBtu in 2014. 2011 excluded BP’s share of TNK-BP dividends; 2014 included BP’s share of Rosneft dividends. The projection
included 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.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Financial and operating 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 tax

Replacement cost proﬁt
Net charge (credit) for non-operating

2014
6,412

2013
31,769

$ million
2012
19,769

(1,462)
(947)
(223)
3,780

(1,548)
(6,463)
(307)
23,451

(1,638)
(6,880)
(234)
11,017

4,293
8,073

230
23,681

411
11,428

items , net of tax

4,620

(10,533)

5,298

Net (favourable) unfavourable

impact of fair value accounting
effects , net of tax

Underlying replacement cost proﬁt
Capital expenditure and acquisitions,

(557)
12,136

280
13,428

345
17,071

on accrual basis

23,781

36,612

25,204

a Proﬁt attributable to BP shareholders.

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

(5)

2012

2013

2014

Proﬁt for the year ended 31 December 2014 decreased by $19.7 billion
compared with 2013. Excluding inventory holding losses, replacement cost
(RC) proﬁt also decreased by $15.6 billion compared with 2013. Both
results in 2013 included a $12.5-billion non-operating gain relating to the
disposal of our interest in TNK-BP.

After adjusting for a net charge for non-operating items, which mainly
related to impairments and further charges associated with the Gulf of
Mexico oil spill; and net favourable fair value accounting effects, underlying
RC proﬁt for the year ended 31 December 2014 was down by $1.3 billion
compared with 2013. The reduction was mainly due to a lower proﬁt in
Upstream, partially offset by improved earnings from Downstream.

Proﬁt for the year ended 31 December 2013 increased by $12.4 billion
compared with 2012. Excluding inventory holding losses, RC proﬁt also
increased by $12.2 billion compared with 2012. The increase in both results
was due to a $12.5-billion gain of disposal of our interest in TNK-BP.

After adjusting for a net credit for non-operating items, which mainly
related to the gain on disposal of our interest in TNK-BP and was partially
offset by an $845-million write-off and impairments in Upstream and
further charges associated with the Gulf of Mexico oil spill; and net
unfavourable fair value accounting effects, underlying RC proﬁt for the year
ended 31 December 2013 was down by $3.6 billion compared with 2012.
This 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).

BP Annual Report and Form 20-F 2014

For the year ended 31 December 2012 proﬁt was $11.0 billion, RC proﬁt
was $11.4 billion and underlying RC proﬁt was $17.1 billion. There was a
net post-tax charge of $5.3 billion for non-operating items, which included
a $5-billion pre-tax charge relating to the Gulf of Mexico.

More information on non-operating items, and fair value accounting
effects, can be found on page 209. See Gulf of Mexico oil spill on page 36
and Financial statements – Note 2 for further information on the impact of
the Gulf of Mexico oil spill on BP’s ﬁnancial results.

See Upstream on page 24, Downstream on page 29, Rosneft on

page 33 and Other businesses and corporate on page 35 for
further information on segment results.

Taxation
The charge for corporate income taxes in 2014 was lower than 2013. The
effective tax rate (ETR) was 19% in 2014 (2013 21%, 2012 38%). The low
ETR in 2014 reﬂects the impairment charges on which tax credits arise in
relatively high tax rate jurisdictions. The lower ETR in 2013 compared with
2012 primarily reﬂects the gain on disposal of TNK-BP in 2013 for which
there was no corresponding tax charge. The underlying ETR (which
excludes non-operating items and fair value accounting effects) on RC
proﬁt was 36% in 2014 (2013 35%, 2012 30%).

In the current environment, with our current portfolio of assets, the
underlying ETR on RC proﬁt for 2015 is expected to be lower than 2014.

Cash ﬂow and net debt information

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
Gross debt
Net debt
Gross debt to gross debt-plus-equity
Net debt to net debt-plus-equity

2014

2013

32,754
(19,574)
(5,266)

21,100
(7,855)
(10,400)

$ million
2012

20,479
(13,075)
(2,010)

(671)

7,243

2,885

5,458

22,520
29,763
52,854
22,646
31.9%
16.7%

19,635
22,520
48,192
25,195
27.0%
16.2%

14,177
19,635
48,800
27,465
29.0%
18.7%

Net cash provided by operating activities
Net cash provided by operating activities for the year ended 31 December
2014 increased by $11.7 billion compared with 2013. Excluding the impacts
of the Gulf of Mexico oil spill, net cash provided by operating activities was
$32.8 billion for 2014, an increase of $11.6 billion compared with 2013.
Proﬁt before taxation was lower but this was partially offset by movements
in the adjustments for non-cash items, including depreciation, depletion
and amortization, impairments and gains and losses on sale of businesses
and ﬁxed assets. Furthermore, 2013 was impacted by an adverse
movement in working capital and 2014 was favourably impacted.

The increase in 2013 compared with 2012 primarily beneﬁted from the
reduction of $2.3 billion in the cash outﬂow in respect of the Gulf of
Mexico oil spill. Excluding the impacts of the Gulf of Mexico oil spill, net
cash provided by operating activities was $21.2 billion for 2013, compared
with $22.9 billion for 2012, a decrease of $1.7 billion. The decrease was
mainly due to an increase in working capital requirements of $3.9 billion,
which was partially offset by a reduction in income tax paid.

Net cash used in investing activities
Net cash used in investing activities for the year ended 31 December 2014
increased by $11.7 billion compared with 2013. The increase reﬂected a
decrease in disposal proceeds of $18.5 billion, partly offset by a $4.9-billion
decrease 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 in 2013. There was also a decrease in our other
capital expenditure excluding acquisitions of $2.0 billion.

S
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The decrease in 2013 compared with 2012 reﬂected an increase in
disposal proceeds of $10.4 billion, 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 $1.3 billion.

There were no signiﬁcant acquisitions in 2014, 2013 and 2012.

The group has had signiﬁcant levels of capital investment for many years.
Cash ﬂow in respect of capital investment, excluding acquisitions, was
$23.1 billion in 2014 (2013 $30 billion and 2012 $24.8 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.

We expect capital expenditure, excluding acquisitions and asset
exchanges, to be around $20 billion in 2015.

Total cash disposal proceeds received during 2014 were $3.5 billion (2013
$22 billion, 2012 $11.6 billion). In 2013 this included $16.7 billion for the
disposal of BP’s interest in TNK-BP and in 2012 it included $5.6 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. See Financial
statements – Note 3 for more information on disposals.

Net cash used in ﬁnancing activities
Net cash used in ﬁnancing activities for the year ended 31 December 2014
decreased by $5.1 billion compared with 2013. The decrease primarily
reﬂected higher net proceeds of $3.3 billion from long-term ﬁnancing
and a decrease in the net repayment of short-term debt of $1.3 billion.
The $8-billion share repurchase programme was completed in July 2014.

The increase in 2013 compared with 2012 primarily reﬂected the buyback
of shares of $5.5 billion, as part of our $8-billion share repurchase
programme, lower net proceeds of $1.1 billion from long-term ﬁnancing
and an increase in the net repayment of short-term debt of $1.4 billion.

Total dividends paid in 2014 were 39 cents per share, up 6.8% compared
with 2013 on a dollar basis and 1.9% in sterling terms. This equated to a
total cash distribution to shareholders of $5.9 billion during the year (2013
$5.4 billion, 2012 $5.3 billion).

Net debt
Net debt at the end of 2014 decreased by $2.5 billion from the 2013
year-end position. The ratio of net debt to net debt plus equity at the end of
2014 increased by 0.5%.

The total cash and cash equivalents at the end of 2014 were $7.2 billion
higher than 2013.

We will continue to target our net debt ratio in the 10-20% range while
uncertainties remain. Net debt and the ratio of net debt to net debt plus
equity are non-GAAP measures. See Financial statements – Note 25 for
further information on net debt.

For information on ﬁnancing the group’s activities, see Financial
statements – Note 27 and Liquidity and capital resources on page 211.

Group reserves and production
Total hydrocarbon proved reserves at 31 December 2014, on an oil
equivalent basis including equity-accounted entities, decreased by 3%
(decrease of 5% for subsidiaries and increase of 1% for equity-accounted
entities) compared with 31 December 2013. Natural gas represented about
44% of these reserves (58% for subsidiaries and 27% for equity-
accounted entities). The change includes a net decrease from acquisitions
and disposals of 39mmboe (all within our subsidiaries). Acquisition activity
in our subsidiaries occurred in Azerbaijan, the US and the UK, and
divestment activity in our subsidiaries occurred in the US and Brazil.

Our total hydrocarbon production for the group was 2% lower compared
with 2013. The decrease comprised a 1% increase (7% increase for liquids
and 4% decrease for gas) for subsidiaries and a 7% decrease (13%
decrease for liquids and 25% increase for gas) for equity-accounted
entities.

For more information on reserves and production, see Oil and gas
disclosures for the group on page 219.

2014

2013

2012

Estimated net proved reservesa
(net of royalties)
Liquids
Crude oilb

Subsidiaries
Equity-accounted entitiesc

Natural gas liquids
Subsidiaries
Equity-accounted entitiesc

Total liquids

Subsidiaries
Equity-accounted entitiesc

Natural gas

Subsidiaries
Equity-accounted entitiesc

Total hydrocarbons

Subsidiaries
Equity-accounted entitiesc

Productiona (net of royalties)
Liquids
Crude oild

Subsidiaries
Equity-accounted entitiese

Natural gas liquids
Subsidiaries
Equity-accounted entitiese

Total liquidsf

Subsidiaries
Equity-accounted entitiese

Natural gas

Subsidiaries
Equity-accounted entitiese

Total hydrocarbonsf

Subsidiaries
Equity-accounted entitiese

million barrels

3,798
5,589
9,387

551
131
682

4,082
5,275
9,357

591
103
693

4,349
5,721
10,070

4,672
5,378
10,050
billion cubic feet
33,264
7,041
40,305
million barrels of oil equivalent
10,408
6,592
17,000

10,243
7,753
17,996

34,187
11,788
45,975

thousand barrels per day

789
1,120
1,909

86
19
105

874
1,139
2,013

795
1,137
1,932

96
27
123

891
1,164
2,056

million cubic feet per day
6,193
1,200
7,393

5,845
1,216
7,060

3,582
5,663
9,244

510
62
572

4,092
5,725
9,817

32,496
12,200
44,695

9,694
7,828
17,523

844
979
1,823

91
12
103

936
991
1,927

5,585
1,515
7,100

thousand barrels of oil equivalent per day
1,959
1,882
1,372
1,348
3,331
3,230

1,898
1,253
3,151

a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes condensate and bitumen.
c Includes BP’s share of Rosneft (2014 and 2013) and TNK-BP reserves (2012). See Rosneft on
page 33 and Supplementary information on oil and natural gas on page 167 for further
information.
d Includes condensate.
e Includes BP’s share of Rosneft (2014 and 2013) and TNK-BP production (2013 and 2012).
See Rosneft on page 33 and Oil and gas disclosures for the group on page 219 for
further information.
f A minor amendment has been made to the split between subsidiaries and equity-accounted
entities for the comparative periods.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Upstream

We continued to actively manage our portfolio to
play to our strengths, divesting non-core assets and
ﬁnding alternative ways to create long-term value.

An operator works the controls at the Rumaila oilﬁeld in Iraq. The ﬁeld
extends 50 miles from end to end.

Our business model and strategy
The 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 2014 our activities took place in 28 countries.

With the exception of the US Lower 48 onshore business, we deliver
our exploration, development and production activities through ﬁve
global technical and operating functions:

(cid:116)(cid:1) 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.

(cid:116)(cid:1) 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 .

(cid:116)(cid:1) The global operations organization is responsible for safe, reliable
and compliant operations, including upstream production assets and
midstream transportation and processing activities.

We optimize and integrate the delivery of these activities with support
from global functions with specialist areas of expertise: technology,
ﬁnance, procurement and supply chain, human resources and
information technology.

In 2015 our US Lower 48 onshore business began operating as a
separate business, with its own governance, processes and systems.
This is designed to promote nimble decision making and innovation so
that BP can be more competitive in the US onshore market, while
maintaining BP’s commitment to safe, reliable and compliant
operations. The business’s approach is to operate in line with industry
standards developed within the context of the highly regulated US
environment. BP’s US Lower 48 business manages a diverse portfolio
which includes an extensive unconventional resource base.

Technologies such as seismic imaging, enhanced oil recovery and
real-time data support our upstream strategy by helping to gain new
access, increase recovery and reserves and improve production
efﬁciency. See Our distinctive capabilities on page 16.

BP Annual Report and Form 20-F 2014

We actively manage our portfolio and are placing increasing emphasis
on accessing, developing and producing from ﬁelds able to provide
the greatest value (including 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.

Our strategy is 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:

(cid:116)(cid:1) A continued focus on safety and the systematic management of risk.

(cid:116)(cid:1) Prioritizing value over volume:

– A more focused portfolio with strengthened incumbent positions

and reduced operating complexity.

– Efﬁcient execution of our base activities, a quality set of major
projects and leveraging our access and exploration expertise.
(cid:116)(cid:1) Disciplined investment in three distinctive engines for growth: deep
water, gas value chains and giant ﬁelds. We maintain a balanced
portfolio of opportunities.

(cid:116)(cid:1) Delivery of competitive operating cash growth through

improvements in efﬁciency and reliability – for both operations and
investment.

(cid:116)(cid:1) Strong relationships built on mutual advantage, deep knowledge of

the basins in which we operate and technology.

Our performance summary
(cid:116)(cid:1) For upstream safety performance see page 40.

(cid:116)(cid:1) Our exploration function gained access to new potential resources

covering more than 47,000km2 in ﬁve countries.

(cid:116)(cid:1) We started up seven major upstream projects.

(cid:116)(cid:1) We achieved an upstream BP-operated plant efﬁciency of 90%.

(cid:116)(cid:1) Our disposals generated $2.5 billion in proceeds in 2014.

Upstream proﬁtability ($ billion)

RC proﬁt before interest and tax

Underlying RC proﬁt before interest and tax

28.3

25.1

26.4

25.2

22.5

19.4

16.7 18.3

15.2

8.9

2010

2011

2012

2013

2014

See Financial performance on page 25 for an explanation of the main
factors inﬂuencing upstream proﬁt.

Outlook for 2015
(cid:116)(cid:1) We expect reported production in 2015 to be higher than 2014,
mainly reﬂecting higher entitlements in production-sharing
agreement (PSA)
regions on the basis of assumed lower oil prices.
Actual reported outcome will depend on the exact timing of project
start-ups, OPEC quotas and entitlement impacts in our PSAs. We
expect underlying production in 2015 to be broadly ﬂat with 2014,
with the base decline being offset by new major project volumes
both from 2014 and 2015.

(cid:116)(cid:1) We expect four major projects to come onstream in 2015 – two in

Angola and one each in Australia and Algeria.

(cid:116)(cid:1) Capital investment in 2015 is expected to decrease, largely reﬂecting
the lower oil price environment and our commitment to continued
capital discipline. The reduction is expected to come primarily from
prioritizing activity in our operations, paring back exploration and
access spend, and shelving a number of marginal projects.

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Committing to the future

The Gulf of Mexico is one of four key areas where we believe further growth in higher-margin
barrels is possible. As the region’s leading acreage holder and largest investor for the last 10 years,
BP has focused its activities on this important location for many years. Our four deepwater
production platforms – Thunder Horse, Atlantis, Mad Dog and Na Kika – are all in the early stages of
their life cycles. These major hubs offer long-term growth opportunities for BP and we aim to
optimize production from them, as well as from our non-operated hubs.

In 2014 we made signiﬁcant progress on a multi-billion dollar investment programme by starting up
three major projects in the region. Na Kika Phase 3 began oil production from our ﬁrst well in
February; our Atlantis North Expansion Phase 2 development started up in April with the ﬁrst of four
planned production wells; and with technical input and support from our experts, Shell-operated
Mars B started up in February. We also entered a strategic partnership with Chevron in January
2015 to explore and develop Paleogene assets, combining our subsurface expertise with Chevron’s
Paleogene development design and build experience.

Our progress highlights the potential of our portfolio to unlock value for investors while also
delivering vital energy resources to the US.

We are strengthening our portfolio of higher-value and longer-life assets.

2014
65,424
8,934

2013
70,374
16,657

$ million
2012
72,225
22,491

6,267

1,608

(3,055)

15,201
19,772

18,265
19,115

19,436
18,520

Brent ($/bbl)

2014

2013

5-year range

150

120

93.65
36.15
87.96

5.70
3.80

60.85

98.95
93.28

105.38
38.38
99.24

$ per barrel
108.94
42.75
102.10
$ per thousand cubic feet
4.75
2.32
$ per barrel of oil equivalent
61.86

5.35
3.07

63.58

108.66
97.99

$ per barrel
111.67
94.13

4.43

$ per million British thermal units
2.79
pence per therm

3.65

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

An extremely cold start to 2014 in North America increased heating
demand and drained storage levels. US gas supply continued to expand in
2014, reaching yet another record production level, in particular supported
by rising liquids-rich gas production.

Henry Hub ($/mmBtu)

2014

2013

5-year range

Financial performance

Sales and other operating revenuesa
RC proﬁt before interest and tax
Net (favourable) unfavourable impact
of non-operating items★ and fair
value accounting effects★

Underlying RC proﬁt before interest

and tax

Capital expenditure and acquisitions
BP average realizationsb
Crude oil
Natural gas liquids
Liquids★

Natural gas
US natural gas

Total hydrocarbons★
Average oil marker pricesc
Brent
West Texas Intermediate
Average natural gas marker prices
Average Henry Hub gas priced

Average UK National Balancing Point

gas pricec

50.01

67.99

59.74

a Includes sales to other segments.
b Realizations are based on sales by consolidated subsidiaries only, which excludes
equity-accounted entities.
c All traded days average.
d Henry Hub First of Month Index.

Market 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.

The dated Brent price in 2014 averaged $98.95 per barrel, after three
consecutive years of prices above $100. Prices averaged about $109
during the ﬁrst half of 2014, but fell sharply during the second half in the
face of continued strong growth of light, sweet oil production in the US and
weak global consumption growth. Brent prices ended the year near $55.

The Henry Hub First of Month Index price was up by 21%, year on year, in
2014 (2013, up by 31%).

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

The UK National Balancing Point gas price in 2014 fell by 26% compared
with 2013 (2013 an increase of 14% on 2012). This reﬂected milder
weather and weak demand in Europe. Lower LNG prices in Asia led to a
reduction in the price of spot LNG available for Europe, which contributed
to the weakness of European spot prices. For more information on the
global energy market in 2014, see page 20.

Financial results
Sales and other operating revenues for 2014 decreased compared with
2013, primarily reﬂecting lower liquids realizations partially offset by higher
production in higher-margin areas, higher gas realizations and higher gas
marketing and trading revenues. The decrease in 2013 compared with
2012 primarily reﬂected lower volumes due to disposals and lower liquids
realizations, partially offset by higher gas marketing and trading revenues.

Replacement cost (RC) proﬁt before interest and tax for the segment
included a net non-operating charge of $6,298 million. This is primarily
related to impairments associated with several assets, mainly in the North

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Major projects portfolio

Alaska

Canada

Point Thomson
West end
development
Liberty
Alaska LNG

Sunrise Phase 1
Pike Phase 1
Pike Phase 2
Sunrise Phase 2
Sunrise South
Terre de Grace

North Sea
Kinnoull
Quad 204
Clair Ridge
Culzean
Alligin
Vorlich
Greater Clair

Norway
Snadd
Valhall West Flank
Hod redevelopment

Algeria

In Salah gas southern ﬁelds
In Amenas compression

Gulf of Mexico
Mars B
Na Kika Phase 3
Atlantis North expansion Phase 2
Thunder Horse water injection
Thunder Horse South expansion
Mad Dog Phase 2
Atlantis water injection expansion
Kaskida
Thunder Horse Northwest expansion
Gila
Tiber

Trinidad & Tobago

Juniper
Angelin
Cassia
Manakin
SEQ-B

Brazil

Itaipu
Wahoo

Angola
CLOV
Greater Plutonio Phase 3
Kizomba Satellites Phase 2
Angola LNG re-start
Zinia Phase 2
Dalia Phase 1b
B18 PCC
B31 SE

Egypt

Key

West Nile Delta –
Taurus/Libra
West Nile Delta –
Giza/Fayoum/Raven
East Nile Delta
Salamat
Satis

Azerbaijan
Chirag oil
Shah Deniz Stage 2

Middle East
z

Oman Kha zan

Started up in 2014.
On track for 2015 start-up.
In progress for 2016
and beyond.

India
KG D6 R Series
KG D6 Satellites
KG D6 D55

Indonesia

Tangguh expansion
Sanga Sanga CBM

Australia

Western Flank Phase A
Persephone
Western Flank Phase B
Browse

Sea and Angola reﬂecting the impact of the lower near-term price
environment, revisions to reserves and increases in expected
decommissioning cost estimates. This also included a charge to write
down the value ascribed to block KG D6 in India as part of the acquisition
of upstream interests from Reliance Industries in 2011. The charge arises
as a result of uncertainty in the future long-term gas price outlook,
following the introduction of a new formula for Indian gas prices, although
we do see the commencement of a transition to market-based pricing as a
positive step. We expect further clarity on the new pricing policy and the
premiums for future developments to emerge in due course. Fair value
accounting effects had a favourable impact of $31 million relative to
management’s view of performance.

The 2013 result included a net non-operating charge of $1,364 million,
which included 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 had an unfavourable impact of
$244 million from fair value accounting effects. 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.

After adjusting for non-operating items and fair value accounting effects, the
decrease in the underlying RC proﬁt before interest and tax compared with
2013 reﬂected lower liquids realizations, higher costs, mainly depreciation,
depletion and amortization and exploration write-offs and the absence of
one-off beneﬁts which occurred in 2013 (see below). This was partly offset
by higher production in higher-margin areas, higher gas realizations and a
beneﬁt from stronger gas marketing and trading activities.

Compared with 2012 the 2013 result 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, one-off beneﬁts related to production
taxes and a cost pooling settlement agreement between the owners of the
Trans-Alaska Pipeline System (TAPS), and higher gas realizations.

Total capital expenditure including acquisitions and asset exchanges in
2014 was higher compared with 2013. This included $469 million in 2014
relating to the purchase of an additional 3.3% equity in Shah Deniz,
Azerbaijan and the South Caucasus Pipeline.

In total, disposal transactions generated $2.5 billion in proceeds during

2014, with a corresponding reduction in net proved reserves of
114mmboe, all within our subsidiaries.

The major disposal transactions during 2014 were the farm-out of a 40%
stake in block 61 in the Khazzan ﬁeld, Oman, to government owned
Makarim Gas Development LLC, for $545 million; the sale of our interests in
four BP-operated oilﬁelds on the North Slope of Alaska to Hilcorp, including
all of BP’s interests in the Endicott and Northstar oilﬁelds and a 50% interest
in each of the Milne Point ﬁeld and the Liberty prospect, together with BP’s
interests in the oil and gas pipelines associated with these ﬁelds for $1.25
billion plus an additional carry of up to $250 million, if the Liberty ﬁeld is
developed; and the sale of our interests in the Panhandle West and Texas
Hugoton gas ﬁelds to Pantera Acquisition Group, LLC for $390 million. Sales
transactions are typically subject to post-closing adjustments and future
payments depending on oil price and production. More information on
disposals is provided in Upstream analysis by region on page 213 and
Financial statements – Note 3.

Provisions for decommissioning increased from $17.2 billion at the end of
2013 to $18.7 billion at the end of 2014. The increase primarily reﬂects
updated estimates of the cost of future decommissioning, additions and
a change in discount rate, partially offset by utilization of provisions,
exchange revaluation and impacts of divestments. Decommissioning costs
are initially capitalized within ﬁxed assets and are subsequently depreciated
as part of the asset.

Exploration

The group explores for oil and natural gas under a wide range of licensing,
joint arrangement
alone or, more frequently, with partners.

and other contractual agreements. We may do this

New access in 2014
We gained access to new potential resources covering more than
47,000km2 in ﬁve countries (Australia, Greenland, UK (North Sea), the US
(Gulf of Mexico) and Morocco, which received ﬁnal government approval in
April 2014). In December, we signed a new PSA with the State Oil
Company of the Republic of Azerbaijan to jointly explore for and develop
potential prospects in the shallow water area around the Absheron
Peninsula in the Azerbaijan sector of the Caspian Sea. This is pending ﬁnal
ratiﬁcation by the government. Additionally, Rosneft and BP signed a
heads of agreement in May 2014 relating to a long-term project for the
exploration and potential development of the Domanik formations in the
Volga-Urals region of Russia.

BP Annual Report and Form 20-F 2014

In January 2015, we received formal licences for El Matariya and Karawan
concessions in Egypt after ratiﬁcation and ﬁnalization of the agreements.

During the year we participated in ﬁve discoveries that are potentially
commercial including: one in Egypt with the BG-operated Notus well in the
El Burg concession; one in the pre-salt play of Angola with the Orca well in
Block 20, operated by Cobalt International Energy; one at Xerelete in Brazil’s
Campos basin, operated by Total; one at Vorlich in the North Sea, which
spans the GDF-SUEZ-operated block 30/1f and the BP-operated block 30/1c;
and Guadalupe in the deepwater Gulf of Mexico, operated by Chevron.

Exploration and appraisal costs
Excluding lease acquisitions, the costs for exploration and appraisal costs
were $2,911 million (2013 $4,811 million, 2012 $4,356 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 31% of exploration and appraisal costs were directed
towards appraisal activity. We participated in 67 gross (32.75 net)
exploration and appraisal wells in 10 countries.

Exploration expense
Total exploration expense of $3,632 million (2013 $3,441 million, 2012 $1,475
million) included the write-off of expenses related to unsuccessful drilling
activities or lease expiration in the Lower 48 ($665 million), Algeria ($524
million), India ($139 million), the Gulf of Mexico ($500 million), Brazil ($368
million), China ($112 million), Angola ($110 million), Morocco ($83 million) and
others ($133 million). In addition, $395 million was written off KG D6 in India as
a result of uncertainty in the future long-term gas price outlook (see page 216).

Upstream reserves

Estimated net proved reservesa (net of royalties)
2014

Liquids
Crude oilb
Subsidiaries
Equity-accounted entitiesc

Natural gas liquids
Subsidiaries
Equity-accounted entitiesc

Total liquids
Subsidiariesd
Equity-accounted entitiesc

Natural gas

Subsidiariese
Equity-accounted entitiesc

Total hydrocarbons

Subsidiaries
Equity-accounted entitiesc

3,582
702
4,283

510
16
526

4,092
717
4,809

32,496
2,373
34,869

9,694
1,126
10,821

2013

2012

million barrels

3,798
729
4,527

551
16
567

4,349
745
5,094

4,082
813
4,895

591
25
616

4,672
838
5,510

billion cubic feet
33,264
2,549
35,813

34,187
2,517
36,704

million barrels of oil equivalent
10,408
1,277
11,685

10,243
1,179
11,422

a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes condensate and bitumen.
c BP’s share of reserves of equity-accounted entities in the Upstream segment. During 2014,
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 21 million barrels (21 million barrels at 31 December 2013 and 14 million barrels at
31 December 2012) in respect of the 30% non-controlling interest in BP Trinidad & Tobago LLC.
e Includes 2,519 billion cubic feet of natural gas (2,685 billion cubic feet at 31 December 2013 and
2,890 billion cubic feet at 31 December 2012) 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 segment’s total hydrocarbon reserves on an oil equivalent basis,
including equity-accounted entities at 31 December 2014, decreased by
5% (5% for subsidiaries and 4% for equity-accounted entities) compared
with reserves at 31 December 2013.

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Proved reserves replacement ratio★
The proved reserves replacement ratio for the Upstream segment in 2014,
excluding acquisitions and disposals, was 31% for subsidiaries and
equity-accounted entities (2013 93%), 29% for subsidiaries alone (2013
105%) and 43% for equity-accounted entities alone (2013 30%). For more
information on proved reserves replacement for the group see page 219.
Developments
The map on page 26 shows our major development areas. We achieved
seven major project start-ups in 2014: the Chirag oil project in Azerbaijan;
Na Kika Phase 3, Mars B and Atlantis North expansion Phase 2 in the Gulf
of Mexico; CLOV in Angola; Kinnoull in the North Sea and Sunrise in
Canada. In addition to starting up major projects, 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.

(cid:116) Angola – we had an oil and gas discovery, Orca, in the pre-salt play of
Angola in Block 20 (BP 30%), operated by Cobalt International Energy,
Inc. and the CLOV project reached plateau production of 160mboe/d.

(cid:116)(cid:1) (cid:34)(cid:91)(cid:70)(cid:83)(cid:67)(cid:66)(cid:74)(cid:75)(cid:66)(cid:79)(cid:1)(cid:111) the Shah Deniz and South Caucasus Pipeline consortia
awarded further key contracts for the development of the Shah Deniz
Stage 2 and South Caucasus Pipeline expansion projects. The BP-
operated Azerbaijan International Operating Company celebrated the
20th anniversary of the Azeri-Chirag-Gunashli PSA.

(cid:116)(cid:1) (cid:47)(cid:80)(cid:83)(cid:85)(cid:73)(cid:1)(cid:52)(cid:70)(cid:66)(cid:1)(cid:111) we continued to see high levels of activity, including a new
discovery, Vorlich, in the central North Sea (see page 28); progress in the
major redevelopment of the west of Shetland Schiehallion and Loyal ﬁelds;
and the restart of operations at the Rhum ﬁeld. BP has been granted
seven awards in the UK government’s 28th licensing round. The blocks
are located in three of our core areas: to the north of our Magnus ﬁeld,
next to Vorlich, and west of our Kinnoull development. The government is
still to award some blocks in this round. These blocks are undergoing
environmental assessment.

Unlocking hidden resources

Accessing gas resources locked in hot sandstone almost three miles
below the earth’s surface is a task that our advanced technology and
exploration experience has made possible.

Faced with the particular challenge of Oman’s remote desert, we used
our expertise to safely and successfully complete one of our largest ever
3D seismic surveys across the Khazzan ﬁeld, an area the size of Greater
London. To unlock this huge resource, we used the technical knowledge
we gained from accessing the tight gas★ that is common in our US
Lower 48 onshore business.

We proved our approach by conducting an extended well test –
producing gas from four appraisal wells and acquiring a surveillance
programme that signiﬁcantly helped our understanding of the reservoir
and enabled us to proceed with a ﬁeld development plan. By the end of
2014, we had three rigs in operation and large-scale construction under
way to build the central processing facility, roads and well pads, as well as
workforce accommodation and facilities.

Khazzan represents the ﬁrst phase in developing one of the largest
known tight gas accumulations in the Middle East. It has the potential
to be a major new source of gas supply for Oman over many decades.

We seek efﬁcient ways to deliver projects on time and on budget.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Our total hydrocarbon production for the segment in 2014 was 5% lower
compared with 2013. The decrease comprised a 1% increase (7% increase
for liquids and 4% decrease for gas) for subsidiaries and a 35% decrease
(44% decrease for liquids and 4% increase for gas) for equity-accounted
entities compared with 2013. Divestments in 2014 accounted for 2% of
the year-on-year production decrease. For more information on production
see Oil and gas disclosures for the group on page 219.

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 2.2% higher compared with 2013.
This primarily reﬂects strong Gulf of Mexico performance that was not
impacted by weather, higher entitlements from lower oil prices and ADMA
offshore concession (BP 14.67%) beneﬁting from higher OPEC nomination
for Abu Dhabi.

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 (including liqueﬁed natural gas (LNG)),
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 our 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 and risk management
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, support group LNG activities, and to manage market price risk
and create incremental trading opportunities through the use of commodity
derivative contracts. This activity also enhances margins and generates fee
income from sources such as the management of price risk on behalf of
third-party customers.

The group’s risk governance framework seeks to manage and oversee the
ﬁnancial risks associated with this trading activity, as described in Financial
statements – Note 27.

The group uses a range of commodity derivative contracts, storage and
transport contracts in connection with its trading activities. The range of
contracts that the group enters into is described in Glossary – commodity
trading contracts on page 252.

For an analysis of our upstream business by geographic region

and key events in 2014, see page 213.

(cid:116)(cid:1) (cid:40)(cid:86)(cid:77)(cid:71)(cid:1)(cid:80)(cid:71)(cid:1)(cid:46)(cid:70)(cid:89)(cid:74)(cid:68)(cid:80)(cid:1)(cid:111) we made a new discovery – Guadalupe – and were

awarded 51 blocks in the March and August Gulf of Mexico lease sales.
At the end of the year we had 10 rigs operating. Following our strategic
divestment programme, we now have a focused portfolio with growth
potential around four operated and three non-operated hubs.

Development expenditure of subsidiaries incurred in 2014, excluding
midstream activities, was $15.1 billion (2013 $13.6 billion, 2012
$12.6 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. It includes production from
conventional and unconventional (coalbed methane, shale) assets. The
principal areas of production are Angola, Argentina, Australia, Azerbaijan,
Egypt, Trinidad, the UAE, the UK and the US.

Production (net of royalties)a

Liquids
Crude oil
Subsidiaries
Equity-accounted entities

Natural gas liquids
Subsidiaries
Equity-accounted entities

Total liquidsb
Subsidiaries
Equity-accounted entities

Natural gas

Subsidiaries
Equity-accounted entities

Total hydrocarbonsb

Subsidiaries
Equity-accounted entities

2014

2013

2012

thousand barrels per day

844
163
1,007

91
7
99

936
170
1,106

5,585
431
6,016

789
294
1,083

86
8
94

874
302
1,176

795
281
1,076

96
7
103

891
288
1,179

million cubic feet per day
6,193
416
6,609

5,845
415
6,259

thousand barrels of oil equivalent per day
1,959
1,882
360
374
2,319
2,256

1,898
245
2,143

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 A minor amendment has been made to the split between subsidiaries and equity-accounted
entities for the comparative periods.

Extending the life of the North Sea

This year marked 50 years since we were awarded our ﬁrst licence in
the UK North Sea. And now, after producing more than 5 billion
barrels of oil equivalent, we are not only ﬁnding more oil and gas, but
also extending the life of our existing ﬁelds.

Our latest discovery in the Central North Sea – called Vorlich –
demonstrates the basin’s ongoing potential. The ﬁnd was made
jointly with GDF SUEZ E&P, underlining the beneﬁts increased
collaboration can bring to a mature basin. Vorlich spans two adjacent
but separately operated blocks – one by BP and one by GDF SUEZ.
It has been tested to a ﬂow rate of 5,350 barrels a day.

We identiﬁed Vorlich through analysis of existing wells in the area,
along with detailed mapping of high-quality seismic data, and are
now looking at options to develop it. These options range from a
simple subsea tie back into existing infrastructure, through to
possibly introducing new infrastructure that could also serve to
unlock additional undeveloped resources in the area.

We continue to grow our exploration position using our

leading subsurface capabilities.

BP Annual Report and Form 20-F 2014

Downstream

In 2014 we saw continued improvement in our
process safety and delivered strong operational
performance resulting in proﬁt and operating cash
ﬂow growth.

(cid:116)(cid:1) Fuels marketing and lubricants – we will invest in higher returning
businesses which have operating cash ﬂow growth potential.

(cid:116)(cid:1) Portfolio quality – we will maintain our focus on quality by high-

grading of assets combined with capital discipline. Where businesses
do not ﬁt our strategic frame, we will seek to divest.

(cid:116)(cid:1) Simpliﬁcation and efﬁciency – we have launched a simpliﬁcation and
efﬁciency programme to support performance improvement and to
make our businesses even more competitive.

Implementing this strategy is expected to lead to a growing
downstream earnings proﬁle and increasingly make the business more
robust to external environmental impacts. Growing operating cash
ﬂows and capital discipline should ensure that Downstream remains a
source of increasing cash ﬂow for BP.

S
t
r
a
t
e
g
i
c
r
e
p
o
r
t

Our performance summary
(cid:116)(cid:1) For downstream safety performance see page 41.

(cid:116)(cid:1) We continue to deliver strong operational performance across our
reﬁning system with the Whiting reﬁnery now fully onstream.

(cid:116)(cid:1) We acquired the aviation fuel business, Statoil Fuel and Retail
Aviation AS, to expand our Air BP business in Scandinavia.

(cid:116)(cid:1) We launched a new product, Castrol EDGE boosted with Titanium

Fluid Strength Technology in our lubricants business.

(cid:116)(cid:1) We sold our lubricants global aviation turbine oils business and

completed the sale of our LPG marketing businesses.

(cid:116)(cid:1) We announced that we will halt reﬁning operations at the Bulwer

reﬁnery in Australia in 2015.

(cid:116)(cid:1) In petrochemicals, we decided to invest and retroﬁt some of our

operations in the US and Europe with new proprietary technology
while ceasing certain other operations in our aromatics business as a
result of our strategic review.

Downstream proﬁtability ($ billion)

RC proﬁt before interest and tax

Underlying RC proﬁt before interest and tax

5.6

4.9

6.0

5.5

6.5

2.9

3.6

3.7

4.4

2010

2011

2012

2013

2014

See Financial performance on page 30 for the main factors inﬂuencing
downstream proﬁt.

Outlook for 2015
(cid:116)(cid:1) We anticipate a weaker reﬁning environment due to narrowing crude

differentials in the low crude price environment.

(cid:116)(cid:1) We expect the ﬁnancial impact of reﬁnery turnarounds to be

comparable to that in 2014.

(cid:116)(cid:1) We expect gradual improvement in the petrochemicals margin

environment.

The storage tanks, pipes and towers at BP’s Rotterdam reﬁnery, which can
run at least 70 different kinds of crude.

Our business model and strategy
Our Downstream segment has signiﬁcant operations in Europe, North
America and Asia, and also manufactures and markets products in
Australasia, Africa and Central and South America.

Downstream is the product and service-led arm of BP, made up of
three businesses:

(cid:116)(cid:1) Fuels – includes reﬁneries, fuels marketing and convenience retail

businesses, together with global oil supply and trading activities that
make up fuels value chains (FVCs). We sell reﬁned petroleum
products including gasoline, diesel and aviation fuel.

(cid:116)(cid:1) 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.

(cid:116)(cid:1) Petrochemicals – manufactures products at locations around the
world, mainly using proprietary BP technology. These products are
then used by others to make essential consumer products such as
paint, plastic bottles and textiles.

We aim to run safe and reliable operations across all our businesses,
supported by leading brands and technologies, to deliver high-quality
products and services to meet our customers’ needs.

Our strategy focuses on improving returns, growing operating cash
ﬂow★, and building a quality Downstream business that aims to lead
the industry as measured by net income per reﬁning barrel. Our ﬁve
strategic priorities are:

(cid:116)(cid:1) Safe and reliable operations – this remains our ﬁrst priority and we
continue to drive improvement in personal and process safety
performance.

(cid:116)(cid:1) Advantaged manufacturing – we aim to continue building a top
quartile reﬁning business by having a competitively advantaged
portfolio which is underpinned by operations excellence. In
petrochemicals we seek to create a business with higher earnings
potential which is signiﬁcantly more robust to a bottom of cycle
environment.

Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

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 effects

Fuels
Lubricants
Petrochemicals

Underlying RC proﬁt before interest

and taxb

Fuels
Lubricants
Petrochemicals

Capital expenditure and acquisitions

2014

2013

$ million
2012

80,003

79,394

56,383

227,082
16,401
323,486

258,015
13,786
351,195

274,666
15,342
346,391

2,830
1,407
(499)
3,738

389
(136)
450
703

3,219
1,271
(49)
4,441
3,106

1,518
1,274
127
2,919

712
(2)
3
713

2,230
1,272
130
3,632
4,506

1,403
1,276
185
2,864

3,609
9
(19)
3,599

5,012
1,285
166
6,463
5,249

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.

Financial results
Sales and other operating revenues in 2014 decreased compared with
2013 primarily due to falling crude prices. The increase in 2013, compared
with 2012, reﬂected higher prices largely offset by lower volumes and
foreign exchange losses.

The 2014 result included a net non-operating charge of $1,570 million,
primarily relating to impairment charges in our petrochemicals and fuels
businesses, while 2013 and 2012 results included impairment charges in
our fuels business, which were mainly associated with our disposal
programme. In addition, fair value accounting effects had a favourable
impact of $867 million in 2014 versus unfavourable impacts in 2013 and
2012.

After adjusting for non-operating items and fair value accounting effects,
underlying replacement cost (RC) proﬁt before interest and tax in 2014 was
higher than 2013 but lower than 2012.

Our fuels business

The fuels strategy focuses primarily on fuels value chains (FVCs). These
include large-scale, highly upgraded, feedstock-advantaged reﬁneries
which are integrated with logistics and marketing businesses.

We believe that having a quality reﬁning portfolio connected to strong
marketing positions is core to our integrated FVC businesses as this
provides optimization opportunities in highly competitive markets. We look
to build on our strong portfolio of reﬁning assets and, through advantaged
crude, optimize across the supply chain.

We have improved our reﬁning portfolio quality in terms of crude feedstock
and location advantage, scale and have sustained competitive complexity
through portfolio rationalization and selective investment. Across all
regions we expect to operate our portfolio at top quartile availability and
with improved efﬁciency.

BP Annual Report and Form 20-F 2014

We continue to grow our fuels marketing businesses, including retail,
through differentiated marketing offers and distinctive partnerships. We
partner with leading retailers globally, creating distinctive offers that deliver
good returns and reliable proﬁt and cash generation.

Underlying RC proﬁt before interest and tax was higher than 2013, mainly
due to improved fuels marketing performance, increased heavy crude
processing and higher production, mainly as a result of the ramp-up of
operations at our Whiting reﬁnery following the modernization project. This
was partially offset by a weaker reﬁning environment. Compared with
2012, the 2013 results were impacted by signiﬁcantly weaker reﬁning
margins, reduced throughput due to the planned Whiting reﬁnery outage
as a result of our 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.

Reﬁning marker margin
We track the margin environment by 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. In addition,
the RMM does not include estimates of energy or other variable costs.

Region
US North West

US Midwest

Crude marker
Alaska North
Slope
West Texas
Intermediate

Northwest Europe

Brent

Mediterranean

Azeri Light

Australia

BP RMM

Brent

BP reﬁning marker margin ($/bbl)

2014

2013

5-year range

2014

2013

$ per barrel
2012

16.6

17.4

12.5

10.6

13.5

14.4

15.2

21.7

12.9

10.5

13.4

15.4

18.0

27.8

16.1

12.7

14.8

18.2

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

The average global RMM in 2014 was $14.4/bbl, the lowest level since
2010 and $1.0/bbl lower than 2013. This was largely due to the narrower
West Texas Intermediate-Brent spread as improving pipeline and rail
logistics in the US reduced the discount of US domestic crude oil relative
to the international benchmark.

Reﬁning
At 31 December 2014 we owned or had a share in 14 reﬁneries producing
reﬁned petroleum products that we supply to retail and commercial
customers. For a summary of our interests in reﬁneries and average daily
crude distillation capacities see page 217.

In 2014, reﬁnery operations were strong, with Solomon reﬁning availability
sustained at around 95% and utilization rates of 88% for the year. Overall
reﬁnery throughputs in 2014 were lower than those in 2013, mainly due to
the divestment of the Texas City and Carson reﬁneries.

Reﬁnery throughputsa
USb
Europe
Rest of world
Total

Reﬁning availability
Sales volumes
Marketing salesc
Trading/supply salesd
Total reﬁned product sales
Crude oile
Total

2014

642
782
297
1,721

94.9

2,872
2,448
5,320
2,360
7,680

2013

726
766
299
1,791

2012
thousand barrels per day
1,310
751
293
2,354
%
94.8
thousand barrels per day
3,213
2,444
5,657
1,518
7,175

3,084
2,485
5,569
2,142
7,711

95.3

a Reﬁnery throughputs reﬂect crude oil and other feedstock volumes.
b The Texas City and Carson reﬁneries were both divested in 2013.
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. 88,000 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 that includes pipelines, storage terminals and tankers
for road and rail. We seek to drive for excellence in operational and
transactional processes and deliver compelling customer offers in the
various markets where we operate. For example, in 2014 we added the
capability to receive additional US shale crudes by rail at our Cherry Point
reﬁnery in Washington. This increases the use of location-advantaged
crudes at this reﬁnery, improving access and diversiﬁcation of crude slates.

We supply fuel and related retail services to consumers through company-
owned and franchised retail sites, as well as other channels, including
dealer wholesalers and jobbers. We also 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

2014
7,100
8,000
2,100
17,200

2013
7,700
8,000
2,100
17,800

2012
10,100
8,300
2,300
20,700

S
t
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e
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i
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t

f The number of retail sites includes sites not operated by BP but instead operated by dealers,
jobbers, franchisees or brand licensees 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.

Retail is the most material element of our fuels marketing operations and
has good exposure to growth markets. We have distinctive partnerships
with leading retailers in six countries and plan to expand elsewhere. Retail
is a signiﬁcant source of growth today and is expected to be so in the
future. See Driving success below.

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 our FVCs to maintain a single interface with
oil trading markets and to operate with a single set of trading compliance
and risk management processes, systems and controls. The oil trading
function (including support functions) has trading ofﬁces in Europe, the US
and Asia. Our presence in the more actively-traded regions of the global oil
markets supports overall understanding of the supply and demand forces
across these markets. 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 we will look to
optimize value across the supply chain. For example, we will often sell our
own crude and purchase alternative crudes from third parties for our
reﬁneries where this will provide incremental margin.

Driving success

Since 2005, our retail partnership with Marks &
Spencer (M&S) has gone from strength
to strength, offering a premium convenience
experience that’s helped to drive overall service
station sales growth above the industry average.

Our success is reﬂected not only by our expansion
rate – 26 stores opening across the UK in 2014
– but also by strong sales growth across our
existing M&S Simply Food® forecourts.

The combination of BP and M&S brands
complement each other, creating a highly
differentiated offer for our target customers who
are looking for a forecourt offer that combines
high-quality fuel, premium convenience foods
and the Wild Bean Cafe.

A typical customer’s spend in a M&S Simply
Food® outlet is more than 50% higher than in our
other stores, and we’ve had a signiﬁcant increase
in customers visiting the store speciﬁcally for our
food offer.

BP currently owns and operates nearly 200 BP
forecourts with an M&S Simply Food®.

Our Downstream business provides

signiﬁcant cash generation for the group.

Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Second, the function aims to create and capture incremental trading
opportunities by entering into a full range of exchange-traded commodity
derivatives, over-the-counter 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.

We aim to improve our earnings potential and make the business more
robust to a bottom of cycle environment. We are taking steps to
signiﬁcantly improve the cash break even performance of the business.
This should improve our earnings potential and make the business more
robust to a bottom of cycle environment. The actions to achieve this
include:

The group’s risk governance framework, which seeks to manage and
oversee the ﬁnancial risks associated with this trading activity, is described
in Financial statements – Note 27.

(cid:116)(cid:1) Restructuring a signiﬁcant portion of our portfolio, primarily in our

aromatics business, to shut down older capacity in the US and Asia and
assess disposal options for less advantaged assets.

(cid:116)(cid:1) Retroﬁtting our best technology in our advantaged sites to reduce overall

operating costs.

(cid:116)(cid:1) Growing third-party licensing income to create additional value.

(cid:116)(cid:1) Delivering operational improvements focused on turnaround efﬁciency

and improved reliability.

In addition to the assets we own and operate, we have also invested in a
number of joint arrangements in Asia, where our partners are leading
companies within their domestic market. An example of this is our latest
generation technology PTA plant in China, which we are building with our
partner, Zhuhai Port Co. The plant is currently commissioning with planned
start-up in the ﬁrst half of 2015.

In 2014 the petrochemicals business delivered a lower underlying RC proﬁt
before interest and tax compared with 2013 and 2012. This result reﬂected
a continuation of the weak margin environment, particularly in the Asian
aromatics sector, and unplanned operational events.

Our petrochemicals production in 2014 was ﬂat compared with 2013 and
slightly lower than 2012, with the low margin environment in 2014 and
2013 driving reduced output.

In November 2014 we announced plans to invest more than $200 million
to upgrade PTA plants at Cooper River in South Carolina and Geel in
Belgium using our latest proprietary technology. We expect these
investments to signiﬁcantly increase manufacturing efﬁciency at these
facilities. We plan to continue deploying our technology in new asset
platforms to access Asian demand and advantaged feedstock sources.

The range of contracts that the group enters into is described in Glossary –
commodity trading contracts on page 252.

Aviation
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. We are one of the world’s largest global aviation fuels
suppliers. Air BP serves many major commercial airlines as well as the
general aviation sectors. We have marketing sales of approximately
400,000 barrels per day. For details of acquisitions in 2014, see Running
reliably on page 40.

Our lubricants business
Our lubricants strategy is to focus on our premium brands and growth
markets while leveraging technology and customer relationships. With
more than 50% of proﬁt generated from growth markets and continued
growth in premium lubricants, we have an excellent base for further
expansion and sustained proﬁt growth.

Our lubricants business manufactures and markets lubricants and related
products and services to the automotive, industrial, marine and energy
markets across the world. Our key brands are Castrol, BP and Aral. Castrol
is a recognized brand worldwide which we believe provides us with
signiﬁcant competitive advantage. In technology, we apply our expertise to
create quality lubricants and high-performance ﬂuids for customers in
on-road, off-road, sea and industrial applications globally.

We are one of the largest purchasers of base oil in the market, but have
chosen not to produce it or manufacture additives at scale. Our
participation choices in the value chain are focused on areas where we can
leverage competitive differentiation and strength, such as:

(cid:116)(cid:1) Applying cutting-edge technologies in the development and formulation

of advanced products.

(cid:116)(cid:1) Creating and developing product brands and clearly communicating their

beneﬁts to our customers.

(cid:116)(cid:1) Building and extending our relationships with customers to better

understand and meet their needs.

The lubricants business delivered an underlying RC proﬁt before interest
and tax which is largely consistent with 2013 and 2012 levels. The 2014
result saw an underlying 6% year-on-year improvement in results, which
was offset by adverse foreign exchange translation impacts.

Our petrochemicals business
Our petrochemicals strategy is to own and develop petrochemicals value
chain businesses that are built around proprietary technology to deliver
leading cost positions against our competition. We manufacture and
market four main product lines:

(cid:116)(cid:1) Puriﬁed terephthalic acid (PTA).

(cid:116)(cid:1) Paraxylene (PX).

(cid:116)(cid:1) Acetic acid.

(cid:116)(cid:1) Oleﬁns and derivatives.

We also produce a number of other specialty petrochemicals products.

BP Annual Report and Form 20-F 2014

Rosneft

BP holds a unique position in Russia through its
19.75% share in Rosneft.

Rosneft discovery in the South Kara Sea.

BP and Rosneft
(cid:116)(cid:1) 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.

(cid:116)(cid:1) Russia has signiﬁcant hydrocarbon resources and will continue to play
an important role in long-term energy supply to the global economy.

(cid:116)(cid:1) BP believes the primary sources of value to BP shareholders from its

investment in Rosneft will be potential long-term share price
appreciation and dividend growth.

(cid:116)(cid:1) BP is positioned to contribute to Rosneft’s strategy implementation
through collaboration on technology and best practice. We also have
the potential to undertake standalone projects with Rosneft, both in
Russia and internationally.

(cid:116)(cid:1) We remain committed to our strategic investment in Rosneft while

complying with all relevant sanctions.

2014 summary
(cid:116)(cid:1) US and EU sanctions were imposed on certain Russian activities,

individuals and entities, including Rosneft.

(cid:116)(cid:1) BP received $693 million, net of withholding taxes, in July

– representing our share of Rosneft’s dividend of 12.85 Russian
roubles per share for 2013.

(cid:116)(cid:1) Rosneft and BP signed a contract in June to supply BP with up to

12 million tons of oil products over ﬁve years. A syndicate of banks,
through a pre-export ﬁnancing agreement, made a payment of
approximately $1.935 billion to Rosneft.

(cid:116)(cid:1) Rosneft and BP signed a heads of agreement in May relating to a

long-term project for the exploration and potential development of the
Domanik formations in the Volga-Urals region of Russia.

(cid:116)(cid:1) Rosneft and BP concluded framework agreements in May to enable
technical collaboration between the parties. Work is ongoing in a
number of areas pursuant to these agreements in both upstream and
downstream.

(cid:116)(cid:1) Bob Dudley serves on the Rosneft board of directors, and its strategic

planning committee.

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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 has a major resource base of hydrocarbons onshore and offshore,
with assets in all key hydrocarbon regions of Russia: Western Siberia,
Eastern Siberia, Timan-Pechora, Volga-Urals, North Caucasus, the
continental shelf of the Arctic Sea, and the Far East.

Rosneft participates in international exploration projects or has operations
in countries including the US, Canada, Vietnam, Venezuela, Brazil, Algeria,
United Arab Emirates, Turkmenistan and Norway.

To progress Arctic exploration, it conducted exploration drilling with
ExxonMobil in the South Kara Sea and announced a hydrocarbon discovery
in September. Exxon subsequently suspended its participation in this
project with Rosneft due to sanctions. Rosneft also began production
drilling in the Sea of Okhotsk in September 2014, and continued to grow its
gas business – increasing gas production from 38 to 57bcm as well as
advancing plans for the development of LNG export capacity.

Downstream
Rosneft is the leader of the Russian reﬁning industry. It owns and
operates 10 reﬁneries in Russia and also has an interest in four reﬁneries in
Germany through its Ruhr Oel GmbH partnership with BP. It continued
implementation of the modernization programme for its Russian reﬁneries
in 2014 to signiﬁcantly upgrade and expand reﬁning capacity.

Rosneft reﬁnery throughput in 2014 amounted to 2,027mb/d. As at
31 December 2014, Rosneft owned and operated more than 2,500 retail
service stations, representing the largest network in Russia. This included
BP-branded sites acquired as part of the TNK-BP acquisition in 2013 which
continue to operate under the BP brand under a licence agreement with
BP. 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 segment result includes equity-accounted
earnings from Rosneft, representing BP’s share in Rosneft.

Proﬁt before interest and taxc d
Inventory holding (gains) losses
RC proﬁt before interest and tax
Net charge (credit) for non-operating items
Underlying RC proﬁt before interest and tax
Average oil marker prices
Urals (Northwest Europe – CIF)
Russian domestic oil

2014a
2,076
24
2,100
(225)
1,875

97.23
50.40

$ million
2013b
2,053
100
2,153
45
2,198

$ per barrel
107.38
54.97

a The operational and ﬁnancial information of the Rosneft segment for 2014 is based on preliminary
operational and ﬁnancial results of Rosneft for the three months ended 31 December 2014.
Actual results may differ from these amounts.
b From 21 March 2013.
c 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.
d Includes $25 million (2013 $5 million loss) of foreign exchange losses arising on the
dividend received.

Replacement cost (RC) proﬁt before interest and tax for the segment
included a non-operating gain of $225 million, relating to Rosneft’s sale of
its interest in the Yugragazpererabotka joint venture . In addition, the result
was affected by an unfavourable duty lag effect, lower oil prices and other
items, partially offset by certain foreign exchange effects which had a
favourable impact on the result. See also Financial statements – Notes 15
and 30 for other foreign exchange effects.

Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Balance sheet

Investments in associates a (as at 31 December)

Production and reserves

Production (net of royalties) (BP share)c
Liquids (mb/d)
Crude oild
Natural gas liquids
Total liquids
Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)
Estimated net proved reserves (net of royalties)
(BP share)
Liquids (million barrels)
Crude oild
Natural gas liquids
Total liquids
Natural gas (billion cubic feet)
Total hydrocarbons (mmboe)

2014
7,312

$ million

2013
13,681

2014b

2013

816
5
821
1,084
1,008

4,961
47
5,007
9,827
6,702

643
7
650
617
756

4,860
115
4,975
9,271
6,574

a See Financial statements – Note 15 for further information.
b The operational and ﬁnancial information of the Rosneft segment for 2014 is based on preliminary
operational and ﬁnancial results of Rosneft for the three months ended 31 December 2014.
Actual results may differ from these amounts.
c 2013 reﬂects production for the period 21 March to 31 December, averaged over the full year.
Information on BP’s share of TNK-BP’s production for comparative periods is provided on pages
222 and 223.
d Includes condensate.

BP Annual Report and Form 20-F 2014

Other businesses
and corporate

Comprises our biofuels and wind businesses,
shipping, treasury and corporate activities including
centralized functions.

Crew carrying out mooring operations on the deck of BP’s oil tanker, British
Chivalry, as it berths in Singapore.

Financial performance

Sales and other operating revenuesa
RC proﬁt (loss) before interest and

2014
1,989

2013
1,805

$ million

2012
1,985

tax

(2,010)

(2,319)

(2,794)

Net (favourable) unfavourable impact

of non-operating items

670

421

798

Underlying RC proﬁt (loss) before

interest and tax

Capital expenditure and acquisitions

a Includes sales to other segments.

(1,340)
903

(1,898)
1,050

(1,996)
1,435

The replacement cost (RC) loss before interest and tax for the year ended
31 December 2014 was $2.0 billion (2013 $2.3 billion, 2012 $2.8 billion).
The 2014 result included a net charge for non-operating items of
$670 million (2013 $421 million, 2012 $798 million). This represented
restructuring provisions and impairments, principally in respect of our
biofuels businesses in the UK and US.

After adjusting for these non-operating items, the underlying RC loss
before interest and tax for the year ended 31 December 2014 was
$1.3 billion (2013 $1.9 billion, 2012 $2.0 billion). This result reﬂected
improved shipping, biofuels and wind performance and a number of
one-off credits.

Biofuels
Our investment in alternative energies is focused on biofuels, where our
strategy is to focus on the conversion of cost-advantaged and sustainable
feedstocks that are materially scalable and can be competitive without
subsidies.

We operate three sugar cane mills in Brazil producing bioethanol and sugar
and exporting power to the local grid. We continue to evaluate options to
increase production at these facilities and completed work on expanding
ethanol production capacity at one mill as planned.

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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 our partner DuPont, we are undertaking research into
the production of biobutanol under the company name Butamax.

Across our biofuels business, BP’s share of ethanol-equivalent production
(which includes ethanol and sugar) for 2014 was 653 million litres
compared with 521 million litres in 2013. The majority of this production
was from BP’s sugar cane mills in Brazil.

Wind
We have a wind energy business in the US, with interests in 16 operating
wind farms. Gross generating capacity from this portfolio is 2,585MW of
electricity. Our focus is on safe operations and optimizing performance at
our owned and joint venture wind farms.

Based on our ﬁnancial stake, BP’s net wind generation capacity b was
1,588MW at 31 December 2014, compared with 1,590MW at
31 December 2013. Our net share of wind generation for 2014 was
4,617GWh, compared with 4,203GWh a year ago.

b Capacity ﬁgures include 32MW in the Netherlands managed by our Downstream segment.

Shipping
The primary purpose of BP’s shipping and chartering activities is the
transportation of the group’s hydrocarbon products using a combination of
BP-operated, time-chartered and spot-chartered vessels. Surplus capacity
may also be used to transport third-party products. All vessels conducting BP
shipping activities are subject to our health, safety, security and environmental
requirements. At 31 December 2014, our ﬂeet included four Alaskan vessels,
46 BP-operated and 41 time-chartered vessels for our deep-sea, international
oil and gas shipping operations. In December 2014 BP shipping entered into
contracts with Daewoo Shipbuilding & Marine Engineering in South Korea for
the construction of LNG tankers to be delivered in 2018 and 2019.

Treasury
Treasury manages the ﬁnancing of the group centrally, with responsibility
for managing the group’s debt proﬁle, share buyback programmes and
dividend payments while ensuring liquidity is sufﬁcient to meet group
requirements. It also 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 27.

Insurance
The group generally restricts its purchase of insurance to situations where
this is required for legal or contractual reasons. We bear losses as they
arise, rather than spreading them 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
Other businesses and corporate annual charges, excluding non-operating
items, are expected to be around $1.6 billion in 2015.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Gulf of Mexico oil spill

Economic and environmental restoration progress
continues, while BP makes its case in court.

BP restoration projects in Louisiana include creating a ﬁsh hatchery and
rebuilding and restoring beach, dune and marsh habitat on a number of
coastal islands.

Key events
(cid:116)(cid:1) In April the US Coast Guard ended active clean-up along the Gulf of
Mexico shoreline, with any future identiﬁcation of residual oil to be
dealt with through the National Response Center process.

(cid:116)(cid:1) The federal district court in New Orleans ruled in September that the
discharge of oil was the result of the gross negligence and wilful
misconduct of BP Exploration & Production Inc. BP has appealed this
ruling.

(cid:116)(cid:1) In January 2015 the district court ruled that 3.19 million barrels of oil
were discharged into the Gulf of Mexico and that BP was not grossly
negligent in its source control efforts. We have also appealed this
ruling.

(cid:116)(cid:1) BP continued to challenge the implementation of the settlement

agreement with the Plaintiffs’ Steering Committee, including issues
around compensation for losses with no apparent connection to
the spill. In December, the US Supreme Court declined BP’s petition
to review the lower court decisions relating to these issues.

(cid:116)(cid:1) As at the end of 2014, the cumulative pre-tax income statement

charge since the incident amounted to $43.5 billion. This does not
include amounts that BP does not consider possible to measure
reliably at this time. The magnitude and timing of all possible
obligations continue to be subject to significant uncertainty.

(cid:116)(cid:1) The cumulative charges to be paid from the Deepwater Horizon Oil
Spill Trust fund reached $20 billion in 2014. Subsequent additional
costs are being charged to the income statement as they arise.

Environmental and economic restoration
We have made signiﬁcant progress in completing the response to the
accident and supporting environmental and economic recovery efforts in
affected areas. The US Coast Guard ended patrols and operations on the
ﬁnal shoreline miles in Louisiana in April 2014. The Coast Guard has now
transitioned all shoreline areas to their National Response Center process.
If residual oil from the Deepwater Horizon incident is later identiﬁed and
requires removal, BP will take action at the direction of the Coast Guard.

BP is responsible for the reasonable and necessary costs of assessing
injury to natural resources resulting from the oil spill and of restoration as
deﬁned under the Oil Pollution Act of 1990 (OPA 90). In 2014 activity was
focused on natural resource damage assessment and further progress was
made on early restoration work.

BP Annual Report and Form 20-F 2014

Natural resource damage assessment and early restoration projects
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. The plan will address the identiﬁed
injuries including the recreational use of these resources, as well as an
estimated cost to implement it. By the end of 2014, BP had spent
approximately $1.3 billion to support the assessment process. See
gulfsciencedata.bp.com for environmental data collected through the
natural resource damage assessment process.

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 incident. BP and the trustees, as at December 2014,
had reached agreement on a total of 54 early restoration projects that
are expected to cost approximately $700 million, of which $629 million had
been funded by the end of 2014. BP is providing project funding in
exchange for restoration credits to be applied against the trustees’ ﬁnal
assessment of BP’s natural resource damages funding obligations.

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
on marine and coastal ecosystems. BP has contributed $215 million to
the programme as at 31 December 2014.

Economic recovery
BP continued to support economic recovery efforts in local communities
through a variety of actions and programmes in 2014. By 31 December
2014, BP had spent $13.4 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.

See bp.com/gulfofmexico for more information on environmental and
economic restoration activities.

Multi-district litigation proceedings in New Orleans
The multi-district litigation trial relating to liability, limitation, exoneration
and fault allocation (part of MDL 2179) began in the federal district court in
New Orleans in February 2013.

Phase 1 – causes of the accident and allocation of fault
The district court issued its ruling on the ﬁrst phase of the trial in
September 2014. It found that BP Exploration & Production Inc. (BPXP –
the BP group company that conducts exploration and production
operations in the Gulf of Mexico), BP America Production Company and
various other parties are each liable under general maritime law for the
blowout, explosion and oil spill from the Macondo well. With respect to the
United States’ claim against BPXP under the Clean Water Act, the district
court found that the discharge of oil was the result of BPXP’s gross
negligence and wilful misconduct and that BPXP is therefore subject to
enhanced civil penalties. BP does not believe that the evidence at trial
supports a ﬁnding of gross negligence and wilful misconduct and has
appealed the Phase 1 ruling.

A provision of $3,510 million was recognized in 2010 for estimated civil
penalties under Section 311 of the Clean Water Act. BP continues to
believe that a provision of $3,510 million represents a reliable estimate of
the amount of the liability if the appeal is successful and this provision,
calculated on the basis of the previous assumptions, has been maintained
in the accounts. If BP is unsuccessful in its appeal, and the ruling of gross
negligence and wilful misconduct is upheld, the maximum penalty that
could be imposed is up to $4,300 per barrel. Based upon this penalty rate
and the district court’s ruling of the number of barrels spilled which, as
noted above is also subject to appeal, the maximum penalty could be up to
$13.7 billion. The court has wide discretion in its application of statutory
penalty factors and we are therefore unable to determine a reliable
estimate for any additional penalty which might apply should the gross
negligence ﬁnding be upheld.

Phase 2 – efforts to stop the ﬂow of oil and the volume of oil spilled
The district court issued its ruling on the second phase of the trial in
January 2015. It found that 3.19 million barrels of oil were discharged into
the Gulf of Mexico. In addition, the district court found that BP was not
grossly negligent in its source control efforts. We have also appealed this
Phase 2 ruling.

Penalty phase
The penalty phase of the trial concluded in February 2015. In this phase,
the district court will determine the amount of civil penalties owed to the
United States under the Clean Water Act. This will be based on the court’s
rulings or ultimate determinations on appeal as to the presence of
negligence, gross negligence or wilful misconduct and the volume of oil
spilled, as well as the application of the penalty factors under the Clean
Water Act.

BP is not currently aware of the timing of the district court’s ruling for the
penalty phase.
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 was established to act on behalf of individual and business
plaintiffs in MDL 2179. During 2014, amounts paid out under the PSC
settlements totalled approximately $600 million.

Individual and business claims
As part of its monitoring of payments made by the court-supervised
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. BP has also raised issues about misconduct and
inefﬁciency in the facility administering the settlement.

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
when the revenues and expenses were recorded at different times. In May
2014, the district court approved the claims administrator’s revised
matching policy reﬂecting this order and the policy is now in effect. The
PSC has ﬁled a motion with the district court to alter or amend the policy.

In September 2014 the district court denied BP’s motion to order the
return of excessive payments made by the Deepwater Horizon Court
Supervised Settlement Program under the matching policy in effect
before the district court’s December 2013 ruling requiring a claimant’s
revenue to be matched with variable expenses. BP has appealed this
decision to the US Court of Appeals for the Fifth Circuit (Fifth Circuit).

Following the ruling by the district court, which was afﬁrmed by the
Fifth Circuit, that the settlement agreement did not contain a causation
requirement beyond the revenue and related tests set out in an exhibit
to that agreement, the district court in May dissolved the injunction that
had halted the processing and payment of business economic loss claims
and instructed the claims administrator to resume the processing and
payment of claims. In August BP petitioned the US Supreme Court for
review of the Fifth Circuit’s decisions relating to compensation of claims
for losses with no apparent connection to the Deepwater Horizon spill.
In December 2014 the US Supreme Court denied BP’s petition for review.

Business economic loss claims continue to be assessed and paid under
the revised matching policy. The deadline for submitting claims is 8 June
2015.

In September 2014 BP sought to remove Patrick Juneau from his roles as
claims administrator and settlement trustee for the economic and property
damages settlement for reasons including a conﬂict of interest. This was
denied by the district court and BP has appealed this decision.

Medical claims
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 was one year from the
effective date.

Process safety and ethics monitors
Two independent monitors – a process safety monitor and an ethics
monitor – were appointed under the terms of the criminal plea agreement
BP reached with the US government in 2012 to resolve all federal criminal
claims arising out of the Deepwater Horizon incident. Under the terms of
the agreement, BP is taking additional actions, enforceable by the court, to
further enhance the safety of drilling operations in the Gulf of Mexico.

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The process safety monitor is reviewing and providing recommendations
concerning BPXP’s process safety and risk management procedures for
deepwater drilling in the Gulf of Mexico.

The ethics monitor is reviewing and providing recommendations
concerning BP’s ethics and compliance programme.

The monitors have interviewed BP employees, reviewed policies and
procedures and made site visits in preparation for their initial reports, which
will be delivered in 2015.

A 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. See
bpxpcompliancereports.com for annual updates on BP’s compliance with
the plea agreement.

Other legal proceedings
BP is subject to a number of different legal proceedings in connection
with the Deepwater Horizon incident in addition to the legal proceedings
relating to the PSC settlements and the multi-district litigation proceedings
in New Orleans. For more information see Legal proceedings on page 228.

OPA 90 and other civil claims
BP p.l.c., BPXP and various other BP entities have been among the
companies named as defendants in approximately 3,000 civil lawsuits
resulting from the accident and oil spill, including the claims by several
states and local government entities. The majority of these lawsuits assert
claims under OPA 90, 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 into
MDL 2179.

Alabama, Mississippi, Florida, Louisiana, Texas and various local
government entities have 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 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 90, not
supported by documentation and to be substantially overstated.

Securities litigation proceedings
The multi-district litigation proceedings pending in federal court in
Houston (MDL 2185), including a purported class action on behalf of
purchasers of American Depositary Shares under US federal securities
law, are continuing. A jury trial is scheduled to begin in January 2016.

SEC settlement
In connection with the 2012 settlement with the SEC resolving the SEC’s
Deepwater Horizon-related civil claims, in August 2014, the ﬁnal instalment
of $175 million was paid under the civil penalty of $525 million.

US Environmental Protection Agency (EPA) suspension
and debarment
In March 2014, BP p.l.c., BPXP, and all other BP entities that the EPA had
suspended from receiving new federal contracts or renewing existing ones
entered into an administrative agreement with the EPA resolving all issues
related to suspension or debarment arising from the Deepwater Horizon
incident. The administrative agreement restores the eligibility of BP entities
to enter into new contracts or leases with the US government. Under the
terms and conditions of the administrative agreement, which applies for
ﬁve years, BP has agreed to safety and operations, ethics and compliance
and corporate governance requirements.

BP Annual Report and Form 20-F 2014

Payments made out of the Trust during 2014 totalled $1.7 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 programme
and other resolved items. As at 31 December 2014, the aggregate cash
balances in the Trust and the associated qualiﬁed settlement funds
amounted to $5.1 billion, including $1.1 billion remaining in the seafood
compensation fund, from which a further $0.5 billion partial distribution
started in early 2015, and $0.4 billion held for natural resource damage
early restoration projects.

Financial update

Analysis of cumulative $43.5 billiona charge to the
income statement ($ billion)

■ 1. Spill response
■ 2. Environmental
■ 3. Litigation and claimsb
■ 4. Clean Water Act penalties
■ 5. Other ﬁnes
■ 6. Functional costs

Total

14.3
3.2
16.7
3.5
4.5
1.3

43.5

a The cumulative income statement charge does not include
amounts that BP considers are not possible to measure
reliably at this time.

b The litigation and claims cost is net of recoveries of $5.7 billion.

The group income statement for 2014 includes a pre-tax charge of
$819 million in relation to the Gulf of Mexico oil spill. The charge for
the year reﬂects additional litigation and claims costs and the ongoing
costs of the Gulf Coast Restoration Organization. As at 31 December 2014,
the total cumulative charges recognized to date amount to $43.5 billion.
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 and the timing of such costs will be
dependent on many factors, including in relation to any new information or
future developments. These could have a material impact on our
consolidated ﬁnancial position, results and cash ﬂows.

BP has provided for spill response costs, environmental expenditure,
litigation and claims and Clean Water Act penalties that can be measured
reliably. The cumulative income statement charge does not include
amounts for obligations that BP considers are not possible to measure
reliably at this time, such as:

(cid:116)(cid:1) Natural resource damages, except for reasonable costs for damage

assessment, the $1-billion allocation for early restoration projects and
associated legal costs.

(cid:116)(cid:1) Any obligation that may arise from securities-related litigation.

(cid:116)(cid:1) The cost of business economic loss claims under the PSC settlement
not yet received, or received but not yet processed, or processed but
not yet paid (except where an eligibility notice had been issued before
the end of the month following the balance sheet date and is not subject
to appeal by BP within the claims facility).

(cid:116)(cid:1) Claims asserted in civil litigation, including any further litigation through

excluded parties from the PSC settlement.

(cid:116)(cid:1) Any further liability for the Clean Water Act penalty arising in the event

the gross negligence ﬁnding is upheld.

(cid:116)(cid:1) Any further obligation that may arise from state and local claims.

The additional amounts payable for these and other items could be
considerable. More details regarding the impacts and uncertainties relating
to the Gulf of Mexico oil spill can be found in Risk factors on page 48, Legal
proceedings on page 228 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 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 cumulative charges to the Trust had
reached $20 billion in 2014. Subsequent additional costs over and above
those provided within the $20 billion, are being charged to the income
statement as they arise.

BP Annual Report and Form 20-F 2014

Corporate responsibility

We believe we have a positive role to play in shaping
the long-term future of energy.

Additional information on our safety, environmental and social
performance is available in our Sustainability Report. See
bp.com/sustainability for case studies, country reports
and an interactive tool for health, safety and environmental data.

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Group safety performance
In 2014, BP reported three fatalities; a fall from height in the UK, an
incident involving a forklift in Indonesia and an incident that occurred while
working inside a process vessel in Germany. We deeply regret the loss of
these lives.

Personal safety performance

Recordable injury frequency (group)b
Day away from work case frequencyc

(group)b

Severe vehicle accident rated

2014
0.31

0.081
0.132

2013
0.31

0.070
0.120

2012
0.35

0.076
0.130

b Incidents per 200,000 hours worked.
c Incidents that resulted in an injury where a person is unable to work for a day (shift) or more.
d Number of vehicle incidents that result in death, injury, a spill, a vehicle rollover, or serious
disabling vehicle damage per one million kilometres travelled.

Process safety performance

Tier 1 process safety events★
Tier 2 process safety events
Loss of primary containment –

number of all incidentse

Loss of primary containment –

number of oil spillsf

Number of oil spills to land and water
Volume of oil spilled (thousand litres)
Volume of oil unrecovered

(thousand litres)

2014
28
95

286

156
63
400

155

2013
20
110

261

185
74
724

261

2012
43
154

292

204
102
801

320

e Does not include either small or non-hazardous releases.
f Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).

We report our safety performance using industry metrics including the
American Petroleum Institute (API) RP-754 standard. These include 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. Tier 2 process safety events are those of lesser
consequence than tier 1. We take a long-term view on process safety
indicators because the full beneﬁt of the decisions and actions in this area
is not always immediate.

We seek to record all losses of primary containment (LOPC), regardless of
the volume of the release and report on losses over a severity threshold.
These include unplanned or uncontrolled releases from a tank, vessel,
pipe, rail car or equipment used for containment or transfer. Our 2014 data
reﬂects increases in part due to the introduction of enhanced automated
monitoring for many remote sites in our Lower 48 business.

Our performance in these areas over time suggests that our focus on
safety is having a positive impact. However, we need to continue to
remain vigilant and focused on delivering safe, reliable and compliant
operations.

Managing safety
We are working to continuously improve safety and risk management
across BP. Our operating businesses are responsible for identifying and
managing risks and bringing together people with the right skills and
competencies to address them. They are also required to carry out
self-veriﬁcation and are subject to independent scrutiny and assurance.
Our safety and operational risk team works alongside our operating
businesses to provide oversight and technical guidance, while members
of our group audit teams visit certain sites, including third-party rigs, to
check how they are managing risks.

A safety and health specialist tests a conﬁned space to make sure it’s safe
for entry at the Kwinana reﬁnery in Western Australia.

Safety
We continue to promote deep capability and a safe operating
culture across BP.

(cid:116)(cid:1) Our operating management system (OMS)

sets out BP’s principles

for good operating practice.

(cid:116)(cid:1) By the end of 2014, we had completed 25 of the 26

recommendations from BP’s internal investigation regarding the
Deepwater Horizon accident, the Bly Report.

(cid:116)(cid:1) Contractors carried out 52% of the 357 million hours worked by BP

in 2014.

Process safety events
(number of incidents)

Tier 1

Tier 2

Loss of primary containment

500

400

300

200

100

2010

2011

2012

2013

2014

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

2010
Employees
0.25
Contractors 0.84

2011
0.31
0.41

2012
0.26
0.43

2013
0.25
0.36

2014
0.27
0.34

a API and OGP 2014 data reports are not available until May 2015.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Capability development
We aim to equip our staff with the skills needed to run safe and efﬁcient
operations. Our OMS capability development programmes cover areas
such as process safety, risk, and safety leadership. Our applied deepwater
well control course uses simulator facilities to train key members of rig
teams, including contractors. We have conducted more than 35 classes
for rig crews from around the world since the course began in October
2012.

Security and crisis management
The scale and spread of BP’s operations means we must prepare for a
range of 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.

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. See page 42 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, the Algerian state oil and gas company Sonatrach
and Statoil, came under armed terrorist attack. Algerian military action
regained control of the site. Forty people, including four BP employees,
and a former employee, lost their lives in the incident. This was a tragic
and unprecedented event which impacted many employees and their
families.

BP participated fully in the UK Coroner’s inquest, which we considered
the most effective means of providing a greater understanding of what
happened. The UK Coroner handed down his verdicts, conclusions and
detailed factual ﬁndings on 26 February 2015.

Since the attack, BP and Statoil have jointly carried out an extensive review
of security arrangements in Algeria and have been working with Sonatrach
and the Algerian authorities on a programme of security enhancements.
The Coroner accepted the opinion of his independent security expert who
endorsed the security measures now in place and commented that in his
opinion the security enhancements now provide a signiﬁcantly safer
environment for the staff working there.

Upstream safety

Key safety metrics 2010-2014

Recordable injury frequency
Loss of primary containment
Tier 1 process safety events

120

100

2010

2011

2012

2013

2014

Indexed (2010=100)

Safety performance

Recordable injury frequency
Day away from work case frequency
Loss of primary containment

2014
0.23
0.051

2013
0.32
0.068

2012
0.32
0.053

incidents – number

187

143

151

Safer drilling
Our global wells organization is responsible for planning and executing all
our wells operations across the world. It is also responsible for
establishing standards on compliance, risk management, contractor
management, performance indicators, technology and capability for our
well operations.

Running reliably

Every day Air BP fuels around 6,000 ﬂights – that’s around four a
minute, making safe and efﬁcient processes critical to the way we
operate for each and every one of these ﬂights.

With a combination of ﬂammable liquids, people and aircraft, running
operations safely is Air BP’s ﬁrst priority. Technical and operations
teams are dedicated to servicing customers safely at more than 700
locations across 50 countries.

The business designs, builds and operates aviation fuelling facilities
around the world, and each year it supplies more than 23.2 billion litres
of aviation fuel, helping to make it one of the world’s largest aviation
fuel products and services suppliers.

Air BP is delivering its growth strategy through efﬁcient operations and
investment in assets. In 2014 we expanded our activities with a supply
contract at Brazil’s largest heliport, Helibase, in São Paulo. We also
acquired Statoil Fuel & Retail’s aviation fuel business, which is
principally based in Scandinavia. This has added more than 70 airports
to our global network, helping to position Air BP as one of Scandinavia’s
leading, competitive suppliers.

We prioritize the safety and reliability of our operations.

Each business segment has a safety and operational risk committee,
chaired by the business head, to oversee the management of safety and
operational risk in their respective areas of the business. In addition, the
group operations risk committee facilitates the group chief executive’s
oversight of safety and operational 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
safety and operational risk on the management of the highest priority
risks. SEEAC also receives 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 46.

Operating management system (OMS)
BP’s OMS is a group-wide framework designed to help us manage risks in
our operating activities. It brings together BP requirements on health,
safety, security, the environment, social responsibility and operational
reliability, as well as related issues, such as maintenance, contractor
relations and organizational learning, into a common management system.
Any necessary variations in the application of OMS – in order to meet local
regulations or circumstances – are subject to a governance process.

OMS also helps us improve the quality of our operating activities.
All businesses covered by OMS undertake an annual performance
improvement cycle and assess alignment with the OMS framework.
Recently acquired operations need to transition to OMS. We review and
amend our group requirements within OMS from time to time to reﬂect
BP’s priorities and experience or changing external regulations. See page
41 for information about contractors and joint arrangements .

BP Annual Report and Form 20-F 2014

Completing the Bly Report recommendations
BP’s investigation into the Deepwater Horizon accident, the Bly Report,
made 26 recommendations aimed at further reducing risk across our
global drilling activities. A total of 25 recommendations had been
completed by the end of 2014.

We expect the ﬁnal recommendation to be completed by the end of 2015,
as scheduled. This recommendation involves verifying the implementation
of revised well control and monitoring standards to BP-owned and
BP-contracted offshore rigs. It takes time to fully implement as it requires
training a large proportion of our global wells operating personnel on the
revised standards.

Our group audit team has veriﬁed closure of the recommendations.

See bp.com/26recommendations for the Bly Report recommendations.

The BP board appointed Carl Sandlin as independent expert in 2012 to
provide an objective assessment of BP’s global progress in implementing
the recommendations from the Bly Report. Mr Sandlin also provides his
views on the organizational effectiveness and culture of the global wells
organization, and process safety observations.

As part of his activities in 2014, Mr Sandlin conducted his third round of
visits to regional wells teams with active drilling operations. Mr Sandlin
visited 10 regions in total. During each visit he conducted reviews with
senior managers, and held discussions with key wells personnel and
drilling contractors on site.

Mr Sandlin is engaged through to June 2016.

Downstream safety

Key safety metrics 2010-2014

Recordable injury frequency
Loss of primary containment
Tier 1 process safety events

140

120

100

2010

2011

2012

2013

2014

Indexed (2010=100)

Safety performance

Recordable injury frequency
Day away from work case frequency
Severe vehicle accident rate
Loss of primary containment

incidents – number

2014
0.34
0.121
0.09

2013
0.25
0.063
0.10

2012
0.33
0.089
0.16

101

117

We take measures to prevent leaks and spills at our reﬁneries and other
downstream facilities through well-designed, well-maintained and properly
operated equipment. We also seek to provide safe locations, emergency
procedures and other mitigation measures in the event of a release, ﬁre or
explosion.

We focus on managing the highest priority risks associated with our
storage, handling and processing of hydrocarbons. We use technology,
such as automated systems, which are intended to prevent our gasoline
storage tanks from overﬁlling, to help manage our operations within safe
operating and design limits. In 2014 a total of 12 facilities participated in
our ‘exemplar’ programme, which aims to help sites apply our OMS using
continuous improvement processes.

Process safety expert
The board appointed Duane Wilson as process safety expert for our
downstream activities in 2012 for a three-year term and assigned him to
work in a global capacity with the business. Mr Wilson provided an
independent perspective on the progress that BP’s fuels, lubricants and

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petrochemicals businesses were making toward becoming industry
leaders in process safety performance.

Working with contractors and partners

BP, like our industry peers, rarely works in isolation – we need to work
with contractors, suppliers and partners to carry out our operations. In
2014, 52% of the 357 million hours worked by BP were carried out by
contractors.

Our ability to be a safe and responsible operator depends in part on the
capability and performance of those who help us carry out our operations.
We therefore seek to identify and manage risks in the supply chain
relating to areas such as safety, corruption and money laundering, and aim
to have suitable provisions in our contracts with contractors, suppliers and
partners.

Contractors
We expect and encourage our contractors and their employees to act in a
way that is consistent with our code of conduct. Our OMS includes
requirements and practices for working with contractors.

We seek to set clear and consistent expectations of our contractors. Our
standard model upstream contracts, for example, include health, safety,
security and environmental requirements. Bridging documents are
necessary in some cases to deﬁne how our safety management system
and those of our contractors co-exist to manage risk on site.

To help us manage risks effectively and take advantage of economies of
scale, we are focusing on developing deeper, longer-term relationships
with selected upstream contractors. We have established global
agreements in areas such as engineered equipment and well services.

Our partners in joint arrangements
We seek to work with companies that share our commitment to ethical,
safe and sustainable working practices. Our code of conduct states that
we seek to clearly communicate our relevant expectations to our business
partners, agreeing contractual obligations where applicable.

We have a group framework for identifying and managing BP’s exposure
related to safety, operational, and bribery and corruption risk from our
participation in non-operated joint arrangements.

Typically, our level of inﬂuence or control over a joint arrangement is linked
to the size of our ﬁnancial stake compared with other participants. In
some joint arrangements we act as the operator. Our OMS applies to the
operations of joint arrangements only where we are the operator.

In other cases, one of our 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 generally available
as a reference point for engagement with operators and co-venturers.

The Toledo reﬁnery in Ohio processes around 160,000 barrels of crude oil
each day to make gasoline, jet fuel and other products.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Oil spill preparedness and response
Our requirements for oil spill preparedness and response planning, and
crisis management incorporate what we have learned over many years of
operation, and speciﬁcally from the Deepwater Horizon accident. Almost
three quarters of our businesses with the potential to spill oil have updated
oil spill planning scenarios and response strategies, in line with our new
requirements issued in 2012. We aim to complete the remaining updates
by the end of 2016.

Meeting the requirements is a substantial piece of work and we believe
this has already resulted in a signiﬁcant increase in our oil spill response
capability. For example, this includes using specialized modelling
techniques that help predict the impact of potential spills, the provision of
stockpiles of dispersants and the use of new tools for environmental
monitoring, such as aerial and underwater robotic vehicles.

Enhancing response capabilities
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 be affected by oil spills and develop appropriate response
strategies. We are implementing a mapping system that brings together
geographical, operational, infrastructure, socio-economic, biological and
habitat information to help us identify and better understand potential
impacts of an oil spill.

We are also testing the applicability of a number of emerging technologies
for oil spill response, including the use of robotic vehicles with camera
sensors to locate spills and provide remote visibility for oil spill response at
sea.

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 2014 we shared lessons on dispersant use and
oil spill response technologies with government regulators in Angola, the
UK and the US.

See page 39 for information on volume of oil spilled by our operations in
2014, including volume of oil unrecovered.

Climate change
BP believes that climate change is an important long-term issue that
justiﬁes global action. We are taking steps to address carbon risk and
collaborating with others on climate change issues. For example, we
require our operations to incorporate energy use considerations in their
business plans and to assess, prioritize and implement technologies and
systems that could improve usage. We factor a carbon cost into our own
investments and engineering designs for large new projects, and invest in
lower-carbon energy products. We seek to address potential climate
change impacts on our new projects in the design phase. We have
guidance for existing operations and projects on how to assess potential
climate risks and impacts – to enable mitigation steps to be incorporated
into project planning, design and operations.

Greenhouse gas emissions
We report on direct and indirect GHG emissions on a carbon dioxide-
equivalent (CO2e) basis. Direct emissions include CO2 and methane from
the combustion of fuel and the operation of facilities, and indirect
emissions include those resulting from the purchase of electricity, heat,
steam or cooling. In 2014 we changed our GHG reporting boundary from
a BP equity-share basis to an operational control basis.

Our approach to reporting GHG emissions broadly follows the IPIECA/
API/IOGP Petroleum Industry Guidelines for Reporting GHG Emissions
(the IPIECA guidelines). 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 it is not practical to collect this data.

Environment and society
Throughout the life cycle of our projects and
operations, we aim to manage the environmental
and social impacts of our presence.

(cid:116)(cid:1) Almost three quarters of our businesses with the potential to spill oil
have updated oil spill planning scenarios and response strategies.

(cid:116)(cid:1) We actively monitor and report greenhouse gas (GHG) emissions to

improve our understanding and management of potential carbon risks.

(cid:116)(cid:1) We are working towards aligning with the United Nations Guiding

Principles on Business and Human Rights.

Greenhouse gas emissionsa
(MteCO2 equivalent)

58.0

54.0

50.0

46.0

50.3b

+0.8

–3

+0.6

–0.1

48.6

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a This is based on BP’s equity share basis.
b The reported 2013 ﬁgure of 49.2 MteCO2e has been amended to 50.3 MteCO2e.

Managing our impacts
Our operating sites can have a lifespan of several decades and our
operations are expected to work to reduce their impacts and risks.
This starts in early project planning and continues through operations
and decommissioning.

Our operating management system (OMS) includes practices that set
out requirements and guidance for how we identify and manage
environmental and social impacts. The practices apply to our major
projects , projects that involve new access, those that could affect an
international protected area and some BP acquisition negotiations.

In the early planning stages of these projects, we complete a screening
process to identify the most signiﬁcant environmental and social impacts.
We completed the process for 19 projects in 2014. Following screening,
projects are required to carry out impact assessments, identify mitigation
measures and implement these in project design, construction and
operations.

BP’s environmental expenditure in 2014 totalled $4,024 million (2013
$4,288 million, 2012 $7,230 million). For a breakdown of environmental
expenditure see page 225. This ﬁgure includes a charge of $190 million
relating to the Gulf of Mexico oil spill. For reference, expenditure related to
the Gulf of Mexico oil spill was a credit of $66 million in 2013 and a charge
of $919 million in 2012. For Regulation of the group’s business –
Environmental regulation see page 225.

We review our management of material issues such as greenhouse gas
emissions, water, sensitive and protected areas and oil spill response.
This includes examining emerging risks and actions taken to mitigate
them.

BP Annual Report and Form 20-F 2014

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Greenhouse gas emissions (MteCO2e)

Operational controla
Direct emissions
Indirect emissions
BP equity shareb
Direct emissions
Indirect emissions

2014

2013

2012

54.1
7.2

48.6
6.6

–
–

50.3c
6.6

–
–

59.8
8.4

a Operational control data comprises 100% of emissions from activities that are operated by BP,
going beyond the IPIECA guidelines by including emissions from certain other activities such as
contracted drilling activities. Data for emissions on an operational control basis was not available
prior to 2014.
b BP equity share comprises our share of BP’s consolidated entities and equity-accounted entities,
other than BP’s share of TNK-BP and Rosneft. Rosneft’s emissions data can be found on its
website.
c The reported 2013 ﬁgure of 49.2 MteCO2e has been amended to 50.3 MteCO2e.

The decrease in our GHG emissions is primarily due to the sale of our
Carson and Texas City reﬁneries in the US as part of our divestment
programme. See bp.com/greenhousegas for more information about our
GHG emissions from upstream production, reﬁning throughput and
chemicals produced.

Intensity
In 2014 we changed the intensity ratio we report on from a ﬁnancial to a
production-based one. The ratio of our total GHG emissions reported on
an operational control-based boundary to gross production was
0.25teCO2e/te production in 2014. Gross production comprises upstream
production, reﬁning throughput and petrochemicals produced.

In 2013 we reported the ratio of our total GHG emissions on a BP
equity-share basis to adjusted revenue of those entities or share of
entities included in GHG reporting. This was 0.15kte/$million. Adjusted
revenue reﬂects total revenues and other income, less gains on sales of
businesses and ﬁxed assets.

Greenhouse gas regulation
GHG regulation is increasing globally. For example, we are seeing the
growth of emission pricing schemes in Europe, California and China,
additional monitoring regulations in the US and increased focus on
reducing ﬂaring and methane emissions in many jurisdictions.

We expect that GHG regulation 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. In
industrialized countries, our standard cost assumption is currently $40 per
tonne of CO2 equivalent. 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 GHG emissions.

See page 225 for information on other environmental regulations.

Water
BP recognizes the importance of managing fresh water use and water
discharges effectively in our operations and evaluates risks, including
water scarcity, wastewater disposal and the long-term social and
environmental pressures on local water resources.

We have invested in a specialist water treatment company to support
operations in areas of water scarcity. The company manufactures
desalinization and brine management systems and we aim to trial these
technologies at our operations.

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 risks.

Water and sand constitute on average 99.5% of the injection material
used in hydraulic fracturing. Some of the chemicals that are added to this
when used in certain concentrations, are classiﬁed as hazardous by the
relevant regulatory authorities. BP works with service providers to
minimize their use where possible. We list the chemicals we use in the
fracturing process in material safety data sheets at each site. We also
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 or other state-designated websites.

We aim to minimize air pollutant and GHG emissions, such as methane, at
our operating sites. For example, we use a process called green
completions at the majority of our gas operations in the US. This process,
which we have been using since 2001, captures natural gas that would
otherwise be ﬂared or vented during the completion and commissioning
of wells.

Our US Lower 48 onshore business’s approach is to operate in line with
industry standards developed within the context of the highly regulated
US environment.

See bp.com/unconventionalgas for information about our approach to
unconventional gas and hydraulic fracturing.

Canada’s oil sands
BP is involved in three oil sands lease areas in Canada. Sunrise Phase 1,
operated by Husky Energy, started up at the end of 2014 and we expect
ﬁrst oil to be recovered in the ﬁrst quarter of 2015. Pike Phase 1, operated
by Devon Energy, was granted regulatory approval in November 2014 and
is at the design and planning stage. 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. Projects are managed through
governance committees, with equal representation from BP and our
partners, and approval rights laid out in agreements with our partners.

See bp.com/oilsands for information on BP’s investments in Canada’s
oil sands.

Human rights
We are committed to conducting our business in a manner that respects
the rights and dignity of all people. We 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. We set out our commitments in our human rights
policy. Our code of conduct references the policy, requiring employees to
report any human rights abuse in our operations or in those of our
business partners.

We are delivering our human rights policy by implementing the relevant
sections of the United Nations Guiding Principles on Business and Human
Rights and incorporating them into the processes and policies that govern
our business activities. Our action plan aims to achieve closer alignment
with the UN Guiding Principles over a number of years using a risk-based
approach. Representatives from key functions, including human
resources, ethics and compliance, procurement, security, and safety and
operational risk oversee the plan’s implementation.

In 2014 our actions included:

(cid:116)(cid:1) Human rights training events for more than 270 people, including

awareness training for relevant senior leadership teams and
representatives from functions such as procurement, shipping, ﬁnance
and legal.

(cid:116)(cid:1) The inclusion of human rights clauses in a number of our standard model

contracts.

(cid:116)(cid:1) Participation in the work of oil and gas industry organization IPIECA on

developing shared industry approaches to managing human rights risks in
the supply chain and guidance on responding to community grievances.

(cid:116)(cid:1) Continued implementation of the Voluntary Principles on Security and
Human Rights, with periodic internal assessments to identify areas for
improvement.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Employees

We seek employees who have the right skills and who
understand and embody the values and expected behaviours
that guide everything we do.

(cid:116)(cid:1) Our values and code of conduct set out the expected qualities and

actions of all our people.

(cid:116)(cid:1) We aim for a workforce that is engaged and representative of the

societies where we operate.

(cid:116)(cid:1) We have a bias towards building capability and promoting within the
organization. Where necessary, this is complemented by selective
external recruitment.

Our values

Safety

Respect

Excellence

Courage

One Team

BP headcount
Number of employees at 31 Decembera
Upstream
Downstream
Other businesses and corporate
Total

2014
24,400
48,000
12,100
84,500

2013
24,700
48,000
11,200
83,900

2012
24,200
51,800
10,400
86,400

a Reported to the nearest 100. For more information see Financial statements – Note 33.

The above table includes:

Retail staff
Agricultural, operational and
seasonal workers in Brazil

2014
14,400

2013
14,100

2012
14,700

5,300

4,300

3,500

At the end of December 2014, we had 84,500 employees. This includes
14,400 service station staff and 5,300 agricultural, operational and
seasonal workers in Brazil, which has increased by 1,000 in 2014 due to
the expansion of one of our sugar cane processing mills which was
completed in 2014. Meanwhile, operational headcount decreased in other
areas. We expect our number of employees to align with BP’s smaller
footprint in 2015 and 2016 as we right-size the organization as part of our
response to a lower oil price.

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 use these values as part of our
recruitment, promotion and individual performance assessment
processes. See bp.com/values for more information.

Our people
We aim to develop the talents of our workforce – with a focus on
maintaining safe and reliable operations, engaging and developing our
employees, and increasing the diversity of our workforce.

The group people committee, chaired by the group chief executive, has
overall responsibility for key policy decisions relating to employees and
governance of BP’s people management processes. In 2014 the

Construction work on the Sunrise energy project, based in the Canadian oil
sands of northern Alberta.

See bp.com/humanrights for more information about our approach to
human rights.

Business ethics
Bribery and corruption are signiﬁcant risks in the oil and gas industry.
We have a responsibility to our shareholders and the countries
and communities in which we do business to be ethical and lawful in all
our dealings. Our code of conduct explicitly states that we do not
tolerate bribery and corruption in any of its forms.

Our group-wide anti-bribery and corruption policy applies to all
BP-operated businesses. The policy governs areas such as appropriate
clauses in contracts, risk assessments and training. We target training on
a risk basis and to those employees for whom it is thought to be most
relevant, for example, given speciﬁc incidents or the nature or location of
their role.

Financial transparency
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 preparing to comply with
the transposed EU Accounting Directive in the UK and are participating in
the development of industry guidance. We are awaiting publication of the
ﬁnal rules of the US Dodd-Frank Act, expected to be issued before the
end of 2015.

As a founding member of the Extractive Industries Transparency Initiative
(EITI), BP works with governments, non-governmental organizations and
international agencies to improve transparency and disclosure of
payments to governments. We support governments’ efforts towards
EITI certiﬁcation in countries where we operate and have worked with
many countries on implementation of their EITI commitments, including
Australia, Azerbaijan, Indonesia, Iraq, Norway, Trinidad & Tobago, the UK
and the US.

Enterprise and community development
We run programmes to help build the skills of businesses and to develop
the local supply chain in a number of locations. For example, in Indonesia,
we provide one-on-one business consultancy and technical assistance to
local businesses during the tender process.

BP’s community investments support development that meets local
needs and are relevant to our business activities. We contributed $85
million in social investment in 2014.

See bp.com/society for more information about our social contribution.

BP Annual Report and Form 20-F 2014

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.

Attracting and retaining our people
The complex projects we work on require a wide range of specialist skills
– from the capability to explore for new sources of energy through to
transporting and distributing hydrocarbons safely across the world. We
have a bias towards building capability and promoting from within the
organization. Where necessary, we complement this with selective
external recruitment. In 2014, 84% of new senior leaders were recruited
from within the organization.

A total of 670 graduates joined BP in 2014. We target the ﬁelds of science,
technology, engineering and maths and run initiatives and awareness days
at universities and colleges. We also run ‘future leader’ programmes to
recruit post-graduates. In 2014, 37% of our graduate intake were women
and 50% were from outside the UK and US.

We conduct external assessments for people entering senior managerial
roles to help achieve rigour and objectivity in our hiring and talent
processes. These provide an in-depth analysis of leadership behaviour and
whether candidates have the necessary experience and skills for the role.

Building enduring capability
Our development opportunities help to build the diverse skills and
expertise that we need. We provide a range of opportunities for our
employees, with an increased focus on on-the-job learning. This can
include mentoring, team development days, workshops, seminars, online
learning and international assignments.

A career transition is a critical moment in an employee’s professional
growth. We have moved towards prioritizing learning at these points, for
example, for those joining BP or moving into a new level of management.
We also offer in-role development that covers a range of levels and
subject areas, from effective planning to inclusive leadership and change
management. Employees from 51 countries attended leadership training,
delivered in six different languages in 2014.

Through our internal academies, we provide leading technical, functional,
compliance and leadership learning opportunities. In 2014, we launched
ﬁve academies including the ‘operating management system (OMS)
academy’ that provides training to operations personnel on implementing
and applying OMS.

Diversity
As a global business, we aim for a workforce 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 women
to represent at least 25% of our group leaders – the most senior
managers of our businesses and functions – by 2020. We continue to
support the UK government’s review of gender diversity on boards,
undertaken by Lord Davies in 2011. Currently we have two women on our
board. We are actively seeking qualiﬁed candidates and remain committed
to Lord Davies’ goal of a quarter of our board to be female by the end of
2015. For more information on our board composition see page 58.

Workforce by gender

Numbers as at 31 December
Board directors
Group leaders
Subsidiary directors
All employees

Male
12
426
776
58,700

Female
2
95
125
25,800

Female %
14
18
14
31

At the end of 2014, 22% of our group leaders came from countries other
than the UK and the US, compared with 14% in 2000. We have continued
to increase the number of local leaders and employees in our operations
so that they reﬂect the communities in which we operate. This is
monitored at a local, business and national level.

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.

We aim to ensure equal opportunity in recruitment, career development,
promotion, training and reward for all employees regardless of race,
colour, national origin, religion, gender, age, sexual orientation, gender
identity, marital status, disability, or any other characteristic protected by
applicable laws. Where existing employees become disabled, our policy is
to provide continuing employment and training wherever possible.

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Employee engagement
Executive team members hold regular meetings and webcasts with
employees around the world. Team 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.

Each year, we conduct a survey to gather employees’ views on a wide
range of business topics and to identify areas where we can improve.
Approximately 38,000 people in 70 countries completed our 2014 survey.
We measure employee engagement with our strategic priorities using
questions about perceptions of BP and how it is managed in terms of
leadership and standards. This measure remained stable in 2014 at 72%
(2013 72%, 2012 71%).

Business leadership teams review the results of the survey and agree
actions to address focus areas. The 2014 survey found that employees
remain clear about the safety procedures, standards and requirements
that apply to them and that pride in working at BP has increased steadily
since 2011. Understanding and support of BP’s strategy is strong at senior
levels, but needs further communication and engagement across the
organization – this is a focus area for 2015. Scores related to development
and career opportunities have fallen slightly compared to 2013. We have
been making changes to how we deliver learning and manage talent and
we expect to see beneﬁts in the longer term.

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 group-wide
equity plan which allows employee participation at different levels globally
and is linked to the company’s performance.

The BP code of conduct
Our code of conduct is based on our values and clariﬁes the principles and
expectations for everyone who works at BP. It applies to all employees,
ofﬁcers and members of the board.

Employees, contractors or other third parties who have a question about
our code of conduct or see something they feel to be unsafe, unethical or
potentially harmful can get help through OpenTalk, a confidential helpline
operated by an independent company.

In 2014 1,114 people contacted OpenTalk with concerns or enquiries (2013
1,121, 2012 1,295). The most common concerns 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.

We take steps to identify and correct areas of non-conformance and take
disciplinary action where appropriate. In 2014, our businesses dismissed
157 employees for non-conformance with our code of conduct or unethical
behaviour (2013 113). This excludes dismissals of staff employed at our
retail service stations for incidents such as thefts of small amounts of
money. We have enhanced our human resources processes, resulting in
improved identiﬁcation and recording of code-related dismissals.

Policy on political activity

We do not use BP funds or resources to support any political candidate or
party. 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 provides administrative support to the BP employee political
action committee to facilitate employee involvement and to assess
whether contributions comply with the law and satisfy all necessary
reporting requirements.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

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 48.

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 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, as to
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.

(cid:116)(cid:1) Understand the risk environment, and assess the speciﬁc risks and

Group people committee – for employee risks.

potential exposure for BP.

(cid:116)(cid:1) Determine how best to deal with these risks to manage overall potential

exposure.

(cid:116)(cid:1) Manage the identiﬁed risks in appropriate ways.

Resource commitment meeting – for investment decision risks.

Group ethics and compliance committee – for legal and regulatory

compliance and ethics risks.

(cid:116)(cid:1) Monitor and seek assurance of the effectiveness of the management

Board and its committees

of these risks and intervene for improvement where necessary.

(cid:116)(cid:1) Report up the management chain and to the board on a periodic basis

on how signiﬁcant risks are being managed, monitored, assured and the
improvements that are being made.

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
principal 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. BP requirements, which take into
account applicable laws and regulations, underpin the practical plans
developed to help reduce risk and deliver strong, sustainable performance.
For example, our operating management system (OMS)★ integrates BP
requirements on health, safety, security, environment, social responsibility,
operational reliability and related issues.

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 using a standard framework for
collating risk data, assessing risk management activities, making further
improvements and planning new activities.

Oversight and governance – functional leadership, the executive team,
the board and relevant committees provide oversight to identify,
understand and endorse management of 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 signiﬁcant risks, and dedicated board committees review
and monitor certain risks throughout the year.

BP Annual Report and Form 20-F 2014

BP board.

Audit committee.

Safety, ethics and environment assurance committee.

Gulf of Mexico committee.

Board committees

For information on the board and its committees see page 58.

Risk management processes
As part of BP’s annual planning process, we review the group’s principal
risks and uncertainties. These may be updated throughout the year in
response to changes in internal and external circumstances.

We aim for a consistent basis of measuring risk to allow comparison on
a like-for-like basis, taking into account potential likelihood and impact, and
to inform how we prioritize speciﬁc risk management activities and invest
resources to manage them.

Our risk proﬁle
The nature of our business operations is long term, resulting in many of our
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.

We identify those risks as having a high priority for particular oversight by
the board and its various committees in the coming year. Those identiﬁed
for 2015 are listed on page 47. These may be updated throughout the year
in response to changes in internal and external circumstances.

The oversight and management of other risks is undertaken in the
normal course of business throughout the business and in executive
and board committees. For example market pricing and liquidity reviews
are conducted on a regular basis by the board and executive committees,
including the group ﬁnancial risk committee, to consider how we respond
to market conditions and when making or reviewing investment decisions.
For further information see page 10.

There can be no certainty that our risk management activities will mitigate
or prevent these, or other risks, from occurring.

Further details of the principal risks and uncertainties we face are set
out in Risk factors on page 48.

Risks for particular oversight by the board and its
committees in 2015
The risks for particular oversight by the board and committees in 2015
remain the same as those for 2014 except that we have replaced risks
associated with delivery of our 10-point plan, which has now been
delivered, with those relating to major project delivery – one of our group
key performance indicators.

Gulf of Mexico oil spill
A wide range of risks have arisen as a result of the Gulf of Mexico 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 while protecting and defending BP’s interests.

The committee’s responsibilities include oversight and review of the
following activities: the legal strategy for litigation; 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 and administrative agreements arising out of the accident and
oil spill.

See Legal proceedings page 228, Financial statements – Note 2 and

Gulf of Mexico committee page 69 for further information.

Strategic and commercial risks
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, and heightened political or social tensions or changes in key
relationships could adversely affect the group.

We seek to actively manage this risk through development and maintenance
of relationships with governments and stakeholders and becoming trusted
partners in each country and region. In addition, we closely monitor events
(such as the situation that arose in Ukraine in 2014) and implement risk
mitigation plans where appropriate.

Major project delivery
Renewing our portfolio requires ongoing innovation and development in
exploration, production, processing and distribution. Major projects contribute
signiﬁcantly to reshaping our portfolio and delivering our strategy.

To manage the risks associated with major project delivery, each stage of a
project’s life cycle must meet certain criteria to proceed to the next stage,
or it will be re-assessed to improve value or be discontinued. Additionally,
executive directors regularly review capital allocation at the resource
commitment meetings. In the upstream our global projects organization
focuses speciﬁcally on major projects and the risks to their delivery. We
undertake post-project evaluations to review decision-making processes,
project execution and project outcomes, and share these with other major
projects as appropriate to support continuous improvement.

For information on our major projects portfolio see page 26, and for
a recent example of how we remodel projects see Increasing value
on page 21.

Cybersecurity
The threats to the security of our digital infrastructure continue to evolve
rapidly 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, testing of cyber response procedures and close
co-operation with authorities. Over the past few years our employee
campaigns on topics such as email phishing and the protection of our
information and equipment have helped to raise awareness of these issues.

Safety and operational risks
Process safety, personal safety and environmental risks
The nature of the group’s operating activities 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.

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Our OMS helps us manage these risks and drive performance improvements.
It sets out the rules and principles which govern key risk management
activities such as inspection, maintenance, testing, business continuity and
crisis response planning and competency development. 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.

For more information on safety and our OMS see page 39.

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 information security.

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. We continue to monitor the situation in the Middle East and North Africa
closely.

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 and training covering areas such as anti-bribery and
corruption, anti-money laundering, competition/anti-trust law and international
trade regulations. We seek to keep abreast of new regulations and legislation
and plan our response to them. We offer an independent conﬁdential helpline,
OpenTalk, for employees, contractors and other third parties. Under the terms
of the US Department of Justice settlement, an ethics monitor will also review
and provide recommendations concerning BP’s ethics and compliance
programme.

Find out more about our code of conduct, our business ethics and

the ethics monitor on pages 45, 44 and 37 respectively.

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 manage these
risks, including guidelines speciﬁc to trading, and 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.

For further information see Upstream gas marketing and trading

activities on page 28, Downstream supply and trading on page 31
and Financial statements – Note 27.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Risk factors

The risks discussed below, separately or in combination, could have a
material adverse effect on the implementation of our strategy, our
business, ﬁnancial performance, results of operations, cash ﬂows, liquidity,
prospects, shareholder value and returns and reputation.

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), including the amount of claims, ﬁnes and penalties that
become payable by BP (including as a result of any ultimate determination
of BP’s appeal of the ruling of gross negligence), the outcome or resolution
of current or future litigation and any costs arising from any longer-term
environmental consequences of the incident, the impact of the incident on
our reputation and the resulting possible impact on our licence to operate.
The provisions recognized in the income statement represent the current
best estimates of expenditures required to settle certain present
obligations that can be reliably estimated at the end of the reporting period,
and there are future expenditures for which we currently cannot measure
our obligations reliably. These uncertainties are likely to continue for a
signiﬁcant period. See Financial statements – Note 2.

The risks associated with the incident could also heighten the impact of
other risks the group is exposed to as described below.

Strategic and commercial risks

Prices and markets – our ﬁnancial performance is subject to ﬂuctuating
prices of oil, gas, reﬁned products, exchange rate ﬂuctuations and the
general macroeconomic outlook.

Oil, gas and product prices are subject to international supply and demand
and margins can be volatile. Political developments, increased supply from
new oil and gas sources, technological change, global economic conditions
and the inﬂuence of OPEC can impact supply and prices for our products.
Decreases in oil, gas or product prices could have an adverse effect on
revenue, margins and proﬁtability and, if signiﬁcant, we may have to write
down assets and re-assess the viability of certain projects. A prolonged
period of low prices may impact our cash ﬂows, proﬁt, capital expenditure
and ability to maintain our long-term investment programme. Conversely,
an increase in oil, gas and product prices may not improve margin
performance as there could be increased ﬁscal take, cost inﬂation and
more onerous terms for access to resources. The proﬁtability of our
reﬁning and petrochemicals activities can be volatile, with periodic
over-supply or supply tightness in regional markets and ﬂuctuations in
demand.

Exchange rate ﬂuctuations can create currency exposures and impact
underlying costs and revenues. Crude oil prices are generally set in US
dollars, while products vary in currency. Many of our major project
development costs are denominated in local currencies, which may be
subject to ﬂuctuations against the US dollar.

Access, renewal and reserves progression – our inability to access,
renew and progress upstream resources in a timely manner could
adversely affect our long-term replacement of reserves.

Delivering our group strategy depends on our ability to continually replenish
a strong exploration pipeline of future opportunities to access and produce
oil and natural gas. Competition for access to investment opportunities,
heightened political and economic risks in certain countries where
signiﬁcant hydrocarbon basins are located and increasing technical
challenges and capital commitments may adversely affect our strategic
progress. This, and our ability to progress upstream resources and sustain
long-term reserves replacement, could impact our future production and
ﬁnancial performance.

Major project delivery – failure to invest in the best opportunities
or deliver major projects successfully could adversely affect our
ﬁnancial performance.

We face challenges in developing major projects, particularly in
geographically and technically challenging areas. Operational challenges
and poor investment choice, efﬁciency or delivery at any major project that
underpins production or production growth could adversely affect our
ﬁnancial performance.

Geopolitical – we are exposed to a range of political developments and
consequent changes to the operating and regulatory environment.

We operate and may seek new opportunities in countries and regions
where political, economic and social transition may take place. Political
instability, changes to the regulatory environment or taxation, international
sanctions, expropriation or nationalization of property, civil strife, strikes,
insurrections, acts of terrorism and acts of war may disrupt or curtail our
operations or development activities. These may in turn cause production
to decline, limit our ability to pursue new opportunities, affect the
recoverability of our assets or cause us to incur additional costs, particularly
due to the long-term nature of many of our projects and signiﬁcant capital
expenditure required.

Rosneft investment – our investment in Rosneft may be impacted by
events in or relating to Russia and our ability to recognize our share of
Rosneft’s income, production and reserves may be adversely impacted.

Events in or relating to Russia, including further trade restrictions and other
sanctions, could adversely impact our investment in Russia. To the extent
we are unable in the future to exercise signiﬁcant inﬂuence over our
investment in Rosneft or pursue growth opportunities in Russia, our
business and strategic objectives in Russia and our ability to recognize our
share of Rosneft’s income, production and reserves may be adversely
impacted.

Liquidity, ﬁnancial capacity and ﬁnancial, including credit,
exposure – failure to work within our ﬁnancial framework could impact our
ability to operate and result in ﬁnancial loss.

Failure to accurately forecast, manage or maintain sufﬁcient liquidity and
credit could impact our ability to operate and result in ﬁnancial loss. Trade
and other receivables, including overdue receivables, may not be recovered
and a substantial and unexpected cash call or funding request could disrupt
our ﬁnancial framework or overwhelm our ability to meet our obligations.

An event such as a signiﬁcant operational incident, legal proceedings or a
geopolitical event in an area where we have signiﬁcant activities, could
reduce our credit ratings. This could potentially increase ﬁnancing costs
and limit access to ﬁnancing or engagement in our trading activities on
acceptable terms, which could put pressure on the group’s liquidity. Credit
rating downgrades could trigger a requirement for the company to review
its funding arrangements with the BP pension trustees and may cause
other impacts on ﬁnancial performance. In the event of extended
constraints on our ability to obtain ﬁnancing, we could be required to
reduce capital expenditure or increase asset disposals in order to provide
additional liquidity. See Liquidity and capital resources on page 211 and
Financial statements – Note 27.

Joint arrangements and contractors – we may have limited control
over the standards, operations and compliance of our partners, contractors
and sub-contractors.

We conduct many of our activities through joint arrangements,
associates or with contractors and sub-contractors where we may have
limited inﬂuence and control over the performance of such operations. Our
partners and contractors are responsible for the adequacy of the resources
and capabilities they bring to a project. If these are found to be lacking,
there may be ﬁnancial, operational or safety risks for BP. Should an incident
occur in an operation that BP participates in, our partners and contractors
may be unable or unwilling to fully compensate us against costs we may
incur on their behalf or on behalf of the arrangement. Where we do not
have operational control of a venture, we may still be pursued by regulators
or claimants in the event of an incident.

BP Annual Report and Form 20-F 2014

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Digital infrastructure and cybersecurity – breach of our digital security
or failure of our digital infrastructure could damage our operations and our
reputation.

sometimes conducted in hazardous, remote or environmentally sensitive
locations, where the consequences of such events could be greater than in
other locations.

A breach or failure of our digital infrastructure due to intentional actions
such as attacks on our cybersecurity, negligence or other reasons, could
seriously disrupt our operations and could result in the loss or misuse of
data or sensitive information, injury to people, disruption to our business,
harm to the environment or our assets, legal or regulatory breaches and
potentially legal liability. These could result in signiﬁcant costs or
reputational consequences.

Climate change and carbon pricing – public policies could increase
costs and reduce future revenue and strategic growth opportunities.

Changes in laws, regulations and obligations relating to climate change
could result in substantial capital expenditure, taxes and reduced
proﬁtability. In the future, these could potentially impact our upstream
assets, revenue generation and strategic growth opportunities.

Competition – inability to remain efﬁcient, innovate and retain an
appropriately skilled workforce could negatively impact delivery of our
strategy in a highly competitive market.

Our strategic progress and performance could be impeded if we are
unable to control our development and operating costs and margins, or to
sustain, develop and operate a high-quality portfolio of assets efﬁciently.
We could be adversely affected if competitors offer superior terms for
access rights or licences, or if our innovation in areas such as exploration,
production, reﬁning or manufacturing lags the industry. Our performance
could also be negatively impacted if we fail to protect our intellectual
property.

Our industry faces increasing challenge to recruit and retain skilled and
experienced people in the ﬁelds of science, technology, engineering and
mathematics. Successful recruitment, development and retention of
specialist staff is essential to our plans.

Crisis management and business continuity – potential disruption
to our business and operations could occur if we do not address an
incident effectively.

Our business and operating activities could be disrupted if we do not
respond, or are perceived not to respond, in an appropriate manner to any
major crisis or if we are not able to restore or replace critical operational
capacity.

Insurance – our insurance strategy could expose the group to material
uninsured losses.

BP generally purchases insurance only in situations where this is legally
and contractually required. We typically bear losses as they arise rather
than spreading them over time through insurance premiums. This means
uninsured losses could have a material adverse effect on our ﬁnancial
position, particularly if they arise at a time when we are facing material
costs as a result of a signiﬁcant operational event which could put pressure
on our liquidity and cash ﬂows.

Safety and operational risks

Process safety, personal safety, and environmental risks – we are
exposed to a wide range of health, safety, security and environmental risks
that could result in regulatory action, legal liability, increased costs, damage
to our reputation and potentially denial of our licence to operate.

Technical integrity failure, natural disasters, human error and other adverse
events or conditions could lead to loss of containment of hydrocarbons or
other hazardous materials, as well as ﬁres, explosions or other personal
and process safety incidents, including when drilling wells, operating
facilities and those associated with transportation by road, sea or pipeline.

There can be no certainty that our operating management system or other
policies and procedures will adequately identify all process safety, personal
safety and environmental risks or that all our operating activities will be
conducted in conformance with these systems. See Safety on page 39.

Such events, including a marine incident, or inability to provide safe
environments for our workforce and the public while at our facilities,
premises or during transportation, could lead to injuries, loss of life or
environmental damage. We could as a result face regulatory action and
legal liability, including penalties and remediation obligations, increased
costs and potentially denial of our licence to operate. Our activities are

Drilling and production – challenging operational environments and other
uncertainties can impact drilling and production activities.

Our activities require high levels of investment and are often conducted in
extremely challenging environments which heighten the risks of technical
integrity failure and the impact of natural disasters. The physical
characteristic of an oil or natural gas ﬁeld, and 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.

Security – hostile acts against our staff and activities could cause harm to
people and disrupt our operations.

Acts of terrorism, piracy, sabotage and similar activities directed against our
operations and facilities, pipelines, transportation or digital infrastructure
could cause harm to people and severely disrupt business and operations.
Our activities could also be severely affected by conﬂict, civil strife or
political unrest.

Product quality – supplying customers with off-speciﬁcation products
could damage our reputation, lead to regulatory action and legal liability,
and potentially impact our ﬁnancial performance.

Failure to meet product quality standards could cause harm to people and
the environment, damage our reputation, result in regulatory action and
legal liability, and impact ﬁnancial performance.

Compliance and control risks

US government settlements – our settlements with legal and regulatory
bodies in the US in respect of certain charges related to the Gulf of Mexico
oil spill may expose us to further penalties, liabilities and private litigation or
could result in suspension or debarment of certain BP entities.

Settlements with the US Department of Justice (DoJ) and the US
Securities and Exchange Commission (SEC) impose signiﬁcant compliance
and remedial obligations on BP and its directors, ofﬁcers and employees,
including the appointment of an ethics monitor, a process safety monitor
and an independent third-party auditor. Failure to comply with the terms
of these settlements could result in further enforcement action by the DoJ
and the SEC, expose us 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 reputation
and ﬁnancial performance. Failure to satisfy the requirements or comply
with the terms of the administrative agreement with the US Environmental
Protection Agency (EPA), under which BP agreed to a set of safety and
operations, ethics and compliance and corporate governance
requirements, could result in suspension or debarment of certain
BP entities.

Regulation – changes in the regulatory and legislative environment could
increase the cost of compliance, affect our provisions and limit our access
to new exploration opportunities.

Governments that award exploration and production interests may impose
speciﬁc drilling obligations, environmental, health and safety controls,
controls over the development and decommissioning of a ﬁeld and
possibly, nationalization, expropriation, cancellation or non-renewal of
contract rights. Royalties and taxes tend to be high compared with those of
other commercial activities, and in certain jurisdictions there is a degree of
uncertainty relating to tax law interpretation and changes. Governments
may change their ﬁscal and regulatory frameworks in response to public
pressure on ﬁnances, resulting in increased amounts payable to them or
their agencies.

Such factors could increase the cost of compliance, reduce our proﬁtability
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, decommissioning,
environmental and legal liabilities. Potential changes to pension or ﬁnancial
market regulation could also impact funding requirements of the group.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Following the Gulf of Mexico oil spill, there have been cases of additional
oversight and more stringent regulation of BP and other companies’ oil and
gas activities in the US and elsewhere, particularly relating to
environmental, health and safety controls and oversight of drilling
operations, which could result in increased compliance costs. In addition,
we may be subjected to a higher number of citations and level of ﬁnes
imposed in relation to any alleged breaches of safety or environmental
regulations, which could result in increased costs.

Ethical misconduct and non-compliance – ethical misconduct or
breaches of applicable laws by our businesses or our employees could be
damaging to our reputation.

Incidents of ethical misconduct or non-compliance with applicable laws
and regulations, including anti-bribery and corruption and anti-fraud laws,
trade restrictions or other sanctions, or non-compliance with the
recommendations of the ethics monitor appointed under the terms of the
DoJ and EPA settlements, could damage our reputation, result in litigation,
regulatory action and penalties.

Treasury and trading activities – ineffective management of treasury
and trading activities could lead to business disruption, ﬁnancial loss,
regulatory intervention or damage to our reputation.

We are subject to operational risk around our treasury and trading activities
in ﬁnancial and commodity markets, some of which are regulated. Failure
to process, manage and monitor a large number of complex transactions
across many markets and currencies while complying with all regulatory
requirements could hinder proﬁtable trading opportunities. There is a risk
that a single trader or a group of traders could act outside of our
delegations and controls, leading to regulatory intervention and resulting in
ﬁnancial loss and potentially damaging our reputation. See Financial
statements – Note 27.

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, including reserves
estimates, relies on the integrity of systems and people. Failure to report
data accurately and in compliance with applicable standards could result in
regulatory action, legal liability and damage to our reputation. For a period
of three years after the SEC settlement in December 2012, we are unable
to rely on the US safe harbor provisions regarding forward-looking
statements, which may expose us to future litigation and liabilities in
connection with our public disclosures. See Legal proceedings on
page 228.

The Strategic report was approved by the board and signed on its behalf by David J Jackson, company secretary on 3 March 2015.

BP Annual Report and Form 20-F 2014

Corporate
governance

52 Board of directors

56 Executive team

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58 Governance overview
Board diversity
Board and committee attendance

58
59

59 How the board works

59
59
59
59
60
60
60
60
60

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

61 Board effectiveness

61
61

Induction and board learning
Board evaluation

62 Shareholder engagement

62
62
62
62

Institutional investors
Private investors
AGM
UK Corporate Governance Code compliance

International advisory board

Internal Control Revised Guidance for Directors (Turnbull)

64 Committee reports

64
68
69
71
71

Audit committee
Safety, ethics and environment assurance committee
Gulf of Mexico committee
Nomination committee
Chairman’s committee

72 Directors’ remuneration report

72
74
86

Chairman’s annual statement
Remuneration committee report
Non-executive directors

BP Annual Report and Form 20-F 2014

Board of directors
As at 3 March 2015
See BP’s board governance principles related to director independence on page 239.

Carl-Henric Svanberg
Chairman
Chair of nomination and chairman’s
committees; attends Gulf of Mexico,
SEEACa and remuneration
committees

Bob Dudley
Group chief executive

Paul Anderson
Independent non-executive director
Chair of the SEEAC; member
of the chairman’s, Gulf of Mexico
and nomination committees

Alan Boeckmann
Independent non-executive director
Member of the chairman’s, Gulf of
Mexico and SEEAC committees;
attends the remuneration committee

Admiral Frank Bowman
Independent non-executive director
Member of the chairman’s, SEEAC
and Gulf of Mexico committees

Antony Burgmans
Independent non-executive director
Chair of the remuneration committee;
member of the chairman’s, SEEAC
and nomination committees

Cynthia Carroll
Independent non-executive director
Member of the chairman’s, SEEAC
and nomination committees

George David
Independent non-executive director
Member of the chairman’s, audit,
Gulf of Mexico and remuneration
committees

Ian Davis
Independent non-executive director
Chair of the Gulf of Mexico
committee; member of the
chairman’s, nomination and
remuneration committees

Professor Dame Ann Dowling
Independent non-executive director
Member of the chairman’s, SEEAC
and remuneration committees

Dr Brian Gilvary
Chief ﬁnancial ofﬁcer

Brendan Nelson
Independent non-executive director
Chair of the audit committee;
member of the chairman’s and
nomination committees

Phuthuma Nhleko
Independent non-executive director
Member of the chairman’s
and audit committees

Andrew Shilston
Senior independent non-executive
director
Member of the chairman’s and audit
committees; attends nomination
committee

BP Annual Report and Form 20-F 2014

David Jackson
Company secretary

a
Safety, ethics and environment assurance
committee.

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Carl-Henric Svanberg

Chairman

Tenure
Appointed 1 September 2009

Outside interests
Chairman of AB Volvo

Age 62 Nationality Swedish

Career
Carl-Henric Svanberg became chairman
of the BP board on 1 January 2010.

Carl-Henric 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.

From 2003 until 31 December 2009,
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 and a member of the
Advisory Board of Harvard Kennedy
School. He is also the recipient of the
King of Sweden’s medal for his
contribution to Swedish industry.

Relevant skills and experience
Carl-Henric Svanberg has, throughout
his career, been involved with
businesses with a global reach. He has
done this as both a chairman and a chief
executive ofﬁcer. His experience is very
broad which has assisted him in leading
the board in the development of the
group’s strategy. He is focused on the
development of the board as the
long-term stewards of the company and
ensuring the right combination of skills
and diversity on the board to deliver that
task.

Carl-Henric Svanberg’s performance
has been evaluated by the chairman’s
committee, led by Andrew Shilston.

Bob Dudley

Group chief executive

Tenure
Appointed to the board 6 April 2009

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 the Emirates Foundation
Board of Trustees

Age 59 Nationality American

Career
Bob Dudley became group chief
executive on 1 October 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. 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.

Between 1999 and 2000, Bob 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.
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
2013 following BP’s acquisition of a
stake in Rosneft.

Relevant skills and experience
Bob Dudley has spent his entire career
in the oil and gas industry. He has held
senior management roles in Amoco and
BP and has signiﬁcant experience as the
chief executive ofﬁcer of TNK-BP.

Over the four years that he has been
group chief executive, Bob has used
these skills in leading BP’s recovery. He
initiated the 10-point plan, the main
2014 tasks of which have been
completed. He has changed the way in
which the group operates and focused
its delivery on value not volume. He has
reshaped the group through non-core
asset divestment and has achieved a
clear direction through a set of
consistent values.

Bob Dudley’s performance has been
considered and evaluated by the
chairman’s committee.

Paul Anderson

Independent non-executive director

Tenure
Appointed 1 February 2010

Outside interests
No external appointments

Age 69 Nationality American

Career
Paul Anderson was formerly chief
executive at BHP Billiton and at 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

served as a non-executive director of
BAE Systems PLC and on a number of
boards in the US and Australia, and was
also chief executive ofﬁcer of Pan
Energy Corp and chairman of Spectra
Energy.

Relevant skills and experience
Paul Anderson has spent his career in
the oil and gas industry working with
global organizations. He brings the skills
of an experienced chairman and chief
executive and has played an important
role, as chairman of the SEEAC since
2012, of continuing the board’s focus on
safety and on broader non-ﬁnancial
issues. His experience of business in the
US and its regulatory environment has
greatly assisted the work of the Gulf of
Mexico committee.

Paul has continued to ensure that the
SEEAC’s activities are not limited to the
UK by leading visits, in this year, to Baku
and Brazil.

Alan Boeckmann

Independent non-executive director

Tenure
Appointed 24 July 2014

Outside interests
Non-executive director of Sempra
Energy and Archer Daniels Midland
Board member and trustee of
Eisenhower Medical Center in Rancho
Mirage, California

Age 66 Nationality American

Career
Alan Boeckmann retired as non-
executive chairman of Fluor Corporation
in February 2012, ending a 35-year
career with the company. Between
2002 and 2011, he held the post of
chairman and chief executive ofﬁcer,
and was president and chief operating
ofﬁcer from 2001 to 2002. His tenure
with the company included
responsibility for global operations.

As chairman and chief executive ofﬁcer,
he refocused the company on
engineering, procurement, construction
and maintenance services.

After graduating from the University
of Arizona with a degree in electrical
engineering, he joined Fluor in 1974 as
an engineer and worked in a variety of
domestic and international locations,
including South Africa and Venezuela.

Alan was previously a non-executive
director of BHP Billiton and the
Burlington Santa Fe Corporation, and
has served on the boards of the
American Petroleum Institute, the
National Petroleum Council and the
advisory board of Southern Methodist
University’s Cox School of Business.

He led the formation of the World
Economic Forum’s ‘Partnering Against
Corruption’ initiative in 2004.

Relevant skills and experience
Alan Boeckmann was asked to join the
board because of his deep experience as
a chairman and chief executive ofﬁcer in

the engineering and contracting industry
which was developed not only in the
United States but also globally. He is an
engineer and brings the skills of that
profession to the SEEAC. Over his career
he has been involved in remuneration
matters and will join the remuneration
committee after the 2015 AGM.

Admiral Frank
Bowman

Independent non-executive director

Tenure
Appointed 8 November 2010

Outside interests
President of Strategic Decisions, LLC
Director of Morgan Stanley
Mutual Funds
Director of Naval and Nuclear

Technologies, LLP

Age 70 Nationality American

Career
Frank L Bowman served for more than
38 years in the US Navy, rising to the
rank of Admiral. He commanded the
nuclear submarine USS City of Corpus
Christi and the submarine tender USS
Holland. After promotion to ﬂag ofﬁcer,
he served on the joint staff as director of
political-military affairs and as the chief
of naval personnel. He then served over
eight years as director of the Naval
Nuclear Propulsion Program where he
was responsible for the operations of
more than one hundred reactors aboard
the US navy’s aircraft carriers and
submarines. He holds two masters
degrees in engineering from the
Massachusetts Institute of Technology.

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. He was
elected to the US National Academy of
Engineering in 2009.

Frank is a member of the CNA military
advisory board and has participated in
studies of climate change and its impact
on national security. Additionally he was
co-chair of a National Academies study
investigating the implication of climate
change for naval forces.

Relevant skills and experience
Frank Bowman has a deep knowledge
of engineering coupled with exceptional
experience in safety issues arising from
his time with the US Navy and, later, the
Nuclear Energy Institute. When coupled
with his work on the BP Independent
Safety Review Panel, Admiral Bowman
has direct experience of BP’s safety
goals. In addition, the other roles in his
career give him a broader perspective of
systems and of people. He continues to
make important contributions to the
work of the SEEAC and the Gulf of
Mexico committee.

BP Annual Report and Form 20-F 2014

Antony Burgmans

Independent non-executive director

Tenure
Appointed 5 February 2004

Outside interests
Member of the supervisory board of
SHV Holdings N.V.
Chairman of the supervisory board of
TNT Express
Chairman of Akzo Nobel N.V.

Age 68 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 joined 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.

Relevant skills and experience
Antony Burgmans is an experienced
chairman and chief executive who has
served on the BP board for over 11
years. He spent his executive career at
Unilever where he developed skills in
production, distribution and marketing.
His experience of consumer facing
business has meant that he has been
able to provide the board with deep
insight in the ﬁelds of reputation, brand,
culture and values. He was asked to
remain on the board until 2016 in the
light of rapid board turnover in 2010 and
2011. Antony remains fully independent.

Antony has now led the remuneration
committee for ﬁve years and has
detailed and regular dialogue with
shareholders on remuneration matters.
He will hand the chair of the
remuneration committee to Professor
Dame Ann Dowling in 2015, and, having
previously led the evaluation of the
chairman, he handed this task to
Andrew Shilston this year in anticipation
of standing down at the 2016 AGM.

Cynthia Carroll

Independent non-executive director

Tenure
Appointed 6 June 2007

Outside interests
Non-executive director of Hitachi Ltd.

Age 58 Nationality American

Career
Cynthia Carroll has led multiple large
complex global businesses in the

extractive industries. This has required
deep strategic and operational
involvement. In leading these
businesses a high level of interaction
with governments, the media, special
interest groups and other stakeholders
has been needed.

Cynthia began her career as a petroleum
geologist with Amoco Production
company in Denver, Colorado, after
completing a masters degree in geology.
In 1989, she 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 skills and experience
Cynthia Carroll is an experienced former
chief executive who has spent all of her
career in the extractive industries,
having trained as a petroleum geologist.
Cynthia has been a leader in working to
enhance safety in the mining industry.
She has also made a strong contribution
to the work of the SEEAC and notably
to the nomination committee.

George David

Independent non-executive director

Tenure
Appointed 11 February 2008

Outside interests
Vice-chairman of the Peterson Institute

for International Economics

Age 72 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 and served as its chief
executive ofﬁcer from 1994 until 2008
and as chairman from 1997 until his
retirement in 2009.

Relevant skills and experience
George David has substantial business
and ﬁnancial experience through his
long career with UTC, a business with
signiﬁcant reliance on safety and
technology. His time as a chairman and
a chief executive ofﬁcer has been
valuable in enabling him to engage in the
complexities of global business. He has
previously chaired BP’s technology
advisory council and has brought
insights from that task to the board.

He is an important member of the audit,
remuneration and Gulf of Mexico
committees, bringing a strong US and
global perspective to their deliberations.

Ian Davis

Independent non-executive director

Tenure
Appointed 2 April 2010

Outside interests
Chairman of Rolls-Royce Holdings plc
Non-executive member of the UK’s
Cabinet Ofﬁce
Non-executive director of Johnson &
Johnson, Inc.
Senior adviser to Apax Partners LLP

Age 63 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 in July 2010.

Relevant skills and experience
Ian Davis brings the skills of a managing
director and signiﬁcant ﬁnancial and
strategic experience to the board. He
has worked with and advised global
organizations and companies in the
oil and gas industry. His work in the
public sector and with the Cabinet Ofﬁce
gives him a unique perspective on
government affairs.

He has chaired the Gulf of Mexico
committee since its formation and has
led the board’s oversight of the response
in the Gulf and guided the board’s
consideration of the various legal issues
which continue to arise following the
Deepwater Horizon accident. He has
been an active member of the
remuneration committee.

Professor Dame Ann
Dowling

Independent non-executive director

Tenure
Appointed 3 February 2012

Outside interests
Professor of Mechanical Engineering
at the University of Cambridge
President of the Royal Academy
of Engineering
Member of the Prime Minister’s Council

for Science and Technology

Non-executive member of the board of

the Department for Business,
Innovation & Skills (BIS)

Age 62 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.
She became Head of the Division of
Energy, Fluid Mechanics and

Turbomachinery in the Department of
Engineering in 2002. She was appointed
the UK lead of the Silent Aircraft
Initiative in 2003, a collaboration
between researchers at Cambridge and
MIT. She was head of the Department
of Engineering at the University of
Cambridge from 2009 to 2014. 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 was elected President of the
Royal Academy of Engineering in
September 2014.

Relevant skills and experience
Dame Ann has a strong engineering
background, not only in the academic
world but also in its practical application
in business. She has led the department
of engineering at Cambridge which
is one of the leading centres for
engineering research worldwide.
This has been recognized by her
appointment as President of the Royal
Academy of Engineering. She chairs the
BP technology advisory council which
aims to provide challenge and direction
to the work in the ﬁeld of technology
throughout the group. Dame Ann is a
member of the SEEAC and, having
joined the remuneration committee in
2012, will take its chair when Antony
Burgmans stands down during 2015.

Dr Brian Gilvary

Chief ﬁnancial ofﬁcer

Tenure
Appointed to the board 1 January 2012

Outside interests
Visiting professor at Manchester
University
External advisor to director general
(spending and ﬁnance), HM
Treasury Financial Management
Review Board

Age 53 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. 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.

BP Annual Report and Form 20-F 2014

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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 skills and experience
Andrew Shilston has had a long career
in ﬁnance in the oil and gas industry and
more generally. His knowledge and
experience as a chief ﬁnancial ofﬁcer,
ﬁrstly in Enterprise Oil and then
Rolls-Royce, makes him well suited to
be a member of BP’s audit committee.
This is complemented by his experience
as the chair of the audit committee at
Cairn Energy.

Andrew has very broad experience of
the oil and gas industry which has
assisted the board in its work in
overseeing the group’s strategy and
in particular the evaluation of capital
projects.

As senior independent director he
has contributed to the work of the
nomination committee. He has also
overseen the evaluation of the chairman
in 2014 and will lead the external
evaluation of the board in 2015.

David Jackson

Company secretary

Tenure
Appointed 2003

David Jackson, a solicitor, is a director of
BP Pension Trustees Limited.

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.

Relevant skills and experience
Dr Brian Gilvary has spent his entire
career at BP. He has a strong knowledge
of ﬁnance and trading and a deep
understanding of BP’s assets and
businesses. Having worked in both
Upstream and Downstream, he also has
very broad experience of the business as
a whole.

Brian has consistently worked to further
strengthen the ﬁnance function and has
continued to develop the company’s
engagement with shareholders.

Brian Gilvary’s performance has been
evaluated by the group chief executive
and considered by the chairman’s
committee.

Brendan Nelson

Independent non-executive director

Tenure
Appointed 8 November 2010

Outside interests
Non-executive director and chairman of

the group audit committee of

The Royal Bank of Scotland Group plc
Member of the Financial Reporting
Council Monitoring Committee

Age 65 Nationality British

Career
Brendan Nelson is a chartered
accountant. He was made a partner of
KPMG in 1984 and 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 for six years as a member of
the Financial Services Practitioner Panel
and in 2013 was the president of the
Institute of Chartered Accountants
of Scotland.

Relevant skills and experience
Brendan Nelson has had a long career in
ﬁnance and auditing, particularly in the
areas of ﬁnancial services and trading.
During his career he has also had
management experience at a very
senior level. He is well qualiﬁed to chair
the audit committee and to act as its
ﬁnancial expert. As chair of the audit
committee he has focused particularly
on the oversight of the group’s trading
operations.

All of this is complemented by his
broader business experience and his
role as the chair of the audit committee
of a major bank.

Phuthuma Nhleko

Independent non-executive director

Tenure
Appointed 1 February 2011

Outside interests
Non-executive director of Anglo
American plc
Non-executive director and chairman of
MTN Group Ltd
Chairman of the Pembani Group

Age 54 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.

He stepped down as group chief
executive of MTN Group at the end of
March 2011 and became chairman.
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 skills and experience
Phuthuma Nhleko’s background in
engineering and his broad experience
as a chief executive of a multinational
company enables him to make a broad
contribution to the board. This is
particularly so in the areas of emerging
market economies and the evolution of
the group’s strategy. His ﬁnancial and
commercial experience is also very
relevant to his work on the audit
committee.

Andrew Shilston

Senior independent non-executive
director

Tenure
Appointed 1 January 2012

Outside interests
Non-executive director of Circle
Holdings plc
Chairman of the Morgan Advanced
Materials plc

Age 59 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.

The ages of the board are correct
as at 3 March 2015.

BP Annual Report and Form 20-F 2014

Trinidad, including chief operating ofﬁcer
for Atlantic LNG, and vice president of
operations. Bob has also served in a
variety of engineering and management
positions in onshore US and deepwater
Gulf of Mexico.

Andy Hopwood

Current position
Chief operating ofﬁcer, strategy and
regions, Upstream

Executive team tenure
Appointed 1 November 2010

Outside interests
President TOC-Rocky Mountains Inc.
Vice president BP Corporation North
America Inc.

Age 57 Nationality British

Career
Andy Hopwood is responsible for BP’s
upstream strategy, portfolio, and
leadership of its global regional
presidents.

Andy joined BP in 1980, spending his
ﬁrst 10 years in operations in the North
Sea, Wytch Farm, and Indonesia. In
1989 Andy joined the corporate planning
team formulating BP’s upstream
strategy, and subsequent portfolio
rationalization. Andy held commercial
leadership positions in Mexico and
Venezuela, before becoming the
Upstream’s planning manager. Following
the BP-Amoco merger, Andy spent time
leading BP’s businesses in Azerbaijan,
Trinidad & Tobago, and onshore North
America. In 2009, he joined the
Upstream executive team as head of
portfolio and technology and in 2010
was appointed executive vice president,
exploration and production.

Katrina Landis

Current position
Executive vice president, corporate
business activities

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 55 Nationality American

Career
Katrina Landis is responsible for BP’s
integrated supply and trading activities,
renewable energy activities, 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. In May 2013, she
became executive vice president,
corporate business activities. Since
mid-2010 she has served as an
independent director of Alstom SA, a
world leader in transport infrastructure,
power generation, and transmission,
and is a founding member of Alstom’s
ethics, compliance and sustainability
committee.

Executive team

As at 3 March 2015

Rupert Bondy

Current position
Group general counsel

Executive team tenure
Appointed 1 May 2008

Outside interests
Non-executive director, Indivior PLC

Age 53 Nationality British

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, 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 in May 2008.

Tufan Erginbilgic

Current position
Chief executive, Downstream

Executive team tenure
Appointed 1 October 2014

Outside interests
Independent non-executive director
of GKN plc.

Age 55 Nationality British and Turkish

Career
Tufan Erginbilgic was appointed chief
executive, Downstream on
1 October 2014.

Prior to this, Tufan was the chief
operating ofﬁcer of the fuels business,
accountable for BP’s fuels value chains
worldwide, the global fuels businesses
and the reﬁning, sales and commercial
optimization functions for fuels. Tufan
joined Mobil in 1990 and BP in 1997 and
has held a wide variety of roles in
reﬁning and marketing in Turkey, various
European countries and the UK. In 2004
he became head of the European fuels
business. Tufan took up leadership of
BP’s lubricant business in 2006 before
moving to head the group chief
executive’s ofﬁce. In 2009 he became
chief operating ofﬁcer for the eastern
hemisphere fuels value chains and
lubricants businesses.

Bob Fryar

Current position
Executive vice president, safety and
operational risk

Executive team tenure
Appointed 1 October 2010

Outside interests
No external appointments

Age 51 Nationality American

Career
Bob Fryar is responsible for
strengthening safety, operational risk
management and the systematic
management of operations across the
BP group. He is group head of safety
and operational risk, with accountability
for group-level disciplines including
engineering, health, safety, security, and
the environment. In this capacity, he
looks after the group-wide operating
management system implementation
and capability programmes.

Bob has 29 years’ experience in the oil
and gas industry, having joined Amoco
Production Company in 1985. Between
2010 and 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. Prior to this, Bob was chief
executive of BP Angola and also held
several management positions in

BP Annual Report and Form 20-F 2014

Career
Lamar McKay is responsible for the
Upstream segment which consists of
exploration, development and
production.

Lamar started his career in 1980 with
Amoco and held a range of technical and
leadership roles.

During 1998 to 2000, he worked on the
BP-Amoco merger and served as head
of strategy and planning for the
exploration and production business. In
2000 he became business unit leader
for the central North Sea. In 2001 he
became chief of staff for exploration and
production, and subsequently for BP’s
deputy group chief executive. Lamar
became group vice president, Russia
and Kazakhstan in 2003. He served as a
member of the board of directors of
TNK-BP between February 2004 and
May 2007. In 2007 he was appointed
executive vice president, BP America.
In 2008 he became executive vice
president, special projects where he
led BP’s efforts to restructure the
governance framework for TNK-BP. In
2009 Lamar was appointed chairman
and president of BP America, serving
as BP’s chief representative in the US.
In January 2013, he became chief
executive, Upstream.

Dev Sanyal

Current position
Executive vice president, strategy and
regions

Executive team tenure
Appointed 1 January 2012

Outside interests
Independent non-executive director,
Man Group plc.
Member, Accenture Global Energy
Board
Member, Board of Advisors of the
Fletcher School of Law and
Diplomacy

Age 49 Nationality British and Indian

Career
Dev Sanyal is responsible for Europe,
Asia, strategy and long-term planning,
risk management, 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.
He moved to London as chief of staff
of BP’s worldwide downstream

Bernard Looney

Current position
Chief operating ofﬁcer, production

Executive team tenure
Appointed 1 November 2010

Outside interests
Member of the Stanford University
Graduate School of Business
Advisory Council
Fellow of the Energy Institute

Age 44 Nationality Irish

Career
Bernard Looney is responsible for BP’s
operated production, with speciﬁc
accountability for drilling, operations,
engineering, procurement and supply
chain management, and 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 responsibility for drilling
operations on Thunder Horse in the
deepwater Gulf of Mexico. In 2005 he
became senior vice president for 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. At the same time,
Bernard became a member of the Oil &
Gas UK Board – the North Sea oil and
gas trade association. He became
co-chair in mid-2010. Bernard became
executive vice president, developments,
in October 2010 and took up his current
role in February 2013.

Lamar McKay

Current position
Chief executive, Upstream

Executive team tenure
Appointed 16 June 2008

Outside interests
Member of Mississippi State University
Dean’s Advisory Council

Age 56 Nationality American

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businesses in 2002. In November 2003
he was appointed chief executive ofﬁcer
of Air BP international. 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 was accountable
for the group’s aluminium interests.

Helmut Schuster

Current position
Executive vice president, group human
resources director

Executive team tenure
Appointed 1 March 2011

Outside interests
Non-executive director of Ivoclar
Vivadent AG

Age 54 Nationality Austrian

Career
Helmut Schuster became group human
resources director in March 2011. In this
role he is accountable 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 within
the organization. He has worked in BP
ofﬁces in the US, the UK and continental
Europe and within most parts of
reﬁning, marketing, trading and gas and
power. Before taking on his current role,
his responsibilities as a vice president,
human resources included the reﬁning
and marketing segment of BP, and
corporate and functions. That role saw
him leading the people agenda for
roughly 60,000 people across the globe
that includes businesses such as
petrochemicals, fuels value chains,
lubricants and functional experts across
the group.

The executive team represents the
principal executive leadership of the
BP group. Its members include
BP’s executive directors (Bob
Dudley and Dr Brian Gilvary whose
biographies appear on pages 52-55)
and the senior management listed
left.

The ages of the executive team are
correct as at 3 March 2015.

BP Annual Report and Form 20-F 2014

Governance overview

The nomination committee has continued to assess the mix of the skills
and experience on the board, in particular for the future, and in line with our
aspiration for diversity. Your board has a diverse membership and we
continue to work to increase its diversity. As I have previously commented,
while candidates can be identiﬁed, it is often the case that the timing of
appointments is dependent on those candidates becoming free from
current commitments. You should expect us to make progress in the
current year.

Finally, we have again this year, considered whether all our narrative
reporting is ‘fair, balanced and understandable’. We have applied the
process adopted last year and concluded that this report meets that test.

I believe that the system of governance used by the board has assisted it
to meet the challenges of past years and will do so in the future.

I believe that the system of governance
used by the board has assisted it to meet
the challenges of past years and will do so in
the future.

Carl-Henric Svanberg
Chairman

Introduction from the chairman
2014 was another active year for the board as we continued to work with
Bob Dudley and his team in reshaping the way that BP operates.

Once again, I have been impressed by the time and commitment given by
my board colleagues. We have built on the progress made in 2013 in
developing how the board works in supporting and challenging executive
management. We have had the beneﬁt of being a settled group for several
years now and I believe that this allows us to spend our time wisely. Later
in this report there is a breakdown of our activities. I would, however, like
to highlight several areas.

The 10-point plan set the direction of travel for the group through to 2014.
We worked through the year with executive management to determine our
strategic direction for 2015 and beyond. To do this, we regularly reﬂected
on the impact of economics and geopolitics both in the world and the
markets in which we operate.

This has particularly been the case as the oil price fell during the last
quarter of the year and action was needed to reset the business to a
lower-price environment.

During the year, we reviewed and enhanced the regular information which
comes to the board. This is in response to feedback from directors which
came from our 2013 board evaluation.

We also considered, in some depth, the manner in which the remuneration
committee operates. We have adopted a revised set of tasks for the
committee which reﬂect the need to balance development and
implementation of the remuneration policy for the directors while
overseeing the approach to reward for executives below the board.

BP, with input from board members, has revised its code of conduct with
the aim of simplifying and clarifying its requirements without weakening
their effect. As a board, we are committed to BP’s values and the code,
and have received training on its application.

In 2014 the UK Corporate Governance Code was revised. We have taken
this into account at the board and in the committees whose work it
impacts. There is particular focus on how risk is governed and managed.
As a result there is much for us to consider here and we will be reviewing
our systems ahead of its implementation in 2015.

BP Annual Report and Form 20-F 2014

Board diversity
BP recognizes the importance of diversity, including gender diversity, at the
board and all levels of the group. BP is committed to increasing diversity
across its 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 policy which aims to promote diversity in its
composition. 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.

Implementation of this policy is monitored through agreed metrics. During
its annual evaluation, the board considered diversity as part of the review of
its performance and effectiveness.

The board is supportive of the recommendations contained in Lord Davies’
report Women on Boards for female board representation and has an
aspiration to increase this to 25% by the end of 2015. At the end of 2014
there were two female directors on the board. The nomination committee
is actively considering diverse candidates as part of its wider search for
board candidates and it is anticipated that an appointment is likely to be
made in 2015.

Board diversity as at 31 December 2014

Gender

1. Female directors
2. Male directors

14%

86%

Geographic background

1. UK
2. US
3. Europe excluding UK
4. Rest of world

36%

43%

14%

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Board and committee attendance in 2014

Board

Audit committee
A*

SEEAC

Non-executive
directors

Carl-Henric Svanberg
Paul Anderson1
Alan Boeckmann
Frank Bowman
Antony Burgmans2
Cynthia Carroll3
George David4
Ian Davis
Ann Dowling
Brendan Nelson
Phuthuma Nhleko5
Andrew Shilston6
Executive directors
Bob Dudley
Iain Conn
Brian Gilvary

10
10
4
10
10
10
10
10
10
10
10
10

10
9
10

10
10
4
10
7
9
10
10
10
10
10
9

9
9
10

7c
2
7
7
7

13c
13
13

13
12
12

7
2
7
7
7

Remuneration
committee
B

Gulf of Mexico
committee
B

Nomination
committee
B

Chairman’s
committee
B

11
5
11

11
11c

10
5
11

11
11

5
5
5

6c
6

6
6

5c
5
2
5
5
5
5
5
5
5
5
5

5
5
2
5
4
5
5
5
5
5
5
5

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.

1 Paul Anderson attended all scheduled Gulf of Mexico committee meetings in 2014; however he was unable to attend the meeting on 15 September that was called at short notice due to long-standing
travel arrangements.
2 Antony Burgmans was unable to attend the board teleconference scheduled at short notice on 5 September due to a prior commitment. He was unable to attend the telephone board meeting on 27
October 2014 for health reasons and the board and chairman’s committee meeting on 4 December 2014 due to a conﬂict with other board meetings on the same day.
3 Cynthia Carroll was unable to attend the telephone board meeting on 27 October 2014 due to a conﬂicting board meeting.
4 George David was unable to attend the telephone audit committee meeting on 26 February 2014 due to a clash with travel arrangements.
5 Phuthuma Nhleko was unable to attend the telephone audit committee on 24 April due to a clash with the AGM of another company.
6 Andrew Shilston attended all scheduled board and audit committee meetings in 2014; however he was unable to attend the board and audit teleconferences scheduled at short notice on
5 September 2014 due to a prior overseas commitment.

How the board works

Board governance in BP
The board operates within a system of governance that is set out in the BP
board governance principles. These principles 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.
See bp.com/governance for the board governance principles.

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 principal risks and uncertainties to
BP are identiﬁed and that systems of risk management and
control are in place to mitigate such risk.

Board and executive management succession.

The board seeks to set the ‘tone from the top’ for BP by working with
management to agree the company values and considering speciﬁc issues
including health, safety, the environment and reputation.

Board composition
On 1 January 2015 the board had 14 directors – the chairman, two
executive directors and 11 independent, non-executive directors (NEDs).

Key roles and responsibilities
The chairman
Carl-Henric Svanberg

(cid:116)(cid:1) Provides leadership of the board.
(cid:116)(cid:1) Acts as main point of contact between the board and management.
(cid:116)(cid:1) Speaks on board matters to shareholders and other parties.
(cid:116)(cid:1) Ensures that systems are in place to provide directors with accurate,

timely and clear information to enable the board to operate effectively.

(cid:116)(cid:1) Is responsible for the integrity and effectiveness of the BP board’s

system of governance.

The group chief executive
Bob Dudley

(cid:116)(cid:1) Is responsible for day-to-day management of the group.
(cid:116)(cid:1) Chairs the executive team (ET), the membership of which is set out

on pages 56-57.

The senior independent director
Andrew Shilston

(cid:116)(cid:1) Is available to shareholders if they have concerns that cannot be

addressed through normal channels.

During 2014 Antony Burgmans, BP’s longest serving non-executive
director, has acted as an internal sounding board for the chairman and
served as an intermediary for the other directors with the chairman when
necessary. He has also led the chairman’s evaluation. From the 2015 AGM,
Andrew Shilston will assume these tasks as part of his role as senior
independent director.

Neither the chairman nor the senior independent director is employed as
an executive of the group.

BP Annual Report and Form 20-F 2014

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, letters of appointment for NEDs do not set a ﬁxed time
commitment. 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 BP to perform their
duties effectively and that they will make themselves available for all
regular and ad-hoc meetings.

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 72).

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. It is the view of the board that all
non-executive directors, with the exception of the chairman, are
independent. See page 239 for a description of BP’s board governance
principles relating to director independence.

Antony Burgmans joined the board in February 2004 and by the 2015 AGM
will have served 11 years as a director. In 2012, the board asked him to
remain as a director until the 2016 AGM. The board continues to consider
that his experience as the longest serving board member provides valuable
insight, knowledge and continuity, that he continues to meet its 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 hold
other external appointments. The nomination committee keeps the other
interests of the NEDs under review to ensure that the effectiveness of the
board is not compromised.

Succession

Alan Boeckmann joined the board in July 2014 as a non-executive director.
He is a member of the Gulf of Mexico and the safety, ethics and
environment assurance committees and attends the remuneration
committee.

Iain Conn, chief executive of BP’s Downstream segment, retired from the
board on 31 December 2014.

At BP’s AGM in 2015, George David will retire from the board following
seven years’ service as a non-executive director.

Professor Dame Ann Dowling will take the chair of the remuneration
committee when Antony Burgmans stands down in 2015.

Andrew Shilston and Alan Boeckmann will join the remuneration
committee after the 2015 annual general meeting.

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. At every meeting, the board receives reports from the chair of
each committee that has met since the last meeting. The main areas of
focus by the board during 2014 are shown below.

Board activities

Strategy

Performance

(cid:116)(cid:1)BP Energy Outlook 2035.
(cid:116)(cid:1)(cid:43)(cid:80)(cid:74)(cid:79)(cid:85)(cid:1)(cid:78)(cid:70)(cid:70)(cid:85)(cid:74)(cid:79)(cid:72)(cid:1)(cid:88)(cid:74)(cid:85)(cid:73)(cid:1)(cid:42)(cid:34)(cid:35)(cid:1)
on geopolitical issues.
(cid:116)(cid:1)(cid:45)(cid:80)(cid:79)(cid:72)(cid:14)(cid:85)(cid:70)(cid:83)(cid:78)(cid:1)(cid:85)(cid:70)(cid:68)(cid:73)(cid:79)(cid:80)(cid:77)(cid:80)(cid:72)(cid:90)(cid:1)

(cid:116)(cid:1)(cid:39)(cid:86)(cid:70)(cid:77)(cid:84)(cid:1)(cid:87)(cid:66)(cid:77)(cid:86)(cid:70)(cid:1)(cid:68)(cid:73)(cid:66)(cid:74)(cid:79)(cid:15)
(cid:116)(cid:1)(cid:48)(cid:83)(cid:72)(cid:66)(cid:79)(cid:74)(cid:91)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:66)(cid:77)(cid:1)(cid:68)(cid:66)(cid:81)(cid:66)(cid:67)(cid:74)(cid:77)(cid:74)(cid:85)(cid:90)(cid:15)
(cid:116)(cid:1)(cid:38)(cid:68)(cid:80)(cid:79)(cid:80)(cid:78)(cid:74)(cid:68)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)

competitor outlook.

view.

(cid:116)(cid:1)(cid:36)(cid:73)(cid:74)(cid:70)(cid:71)(cid:1)(cid:70)(cid:89)(cid:70)(cid:68)(cid:86)(cid:85)(cid:74)(cid:87)(cid:70)(cid:8)(cid:84)(cid:1)(cid:83)(cid:70)(cid:81)(cid:80)(cid:83)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:54)(cid:81)(cid:84)(cid:85)(cid:83)(cid:70)(cid:66)(cid:78)(cid:1)(cid:81)(cid:83)(cid:80)(cid:75)(cid:70)(cid:68)(cid:85)(cid:84)(cid:1)(cid:83)(cid:70)(cid:87)(cid:74)(cid:70)(cid:88)(cid:15)
(cid:116)(cid:1)(cid:38)(cid:71)(cid:71)(cid:70)(cid:68)(cid:85)(cid:74)(cid:87)(cid:70)(cid:79)(cid:70)(cid:84)(cid:84)(cid:1)(cid:80)(cid:71)(cid:1)

(cid:116)(cid:1)(cid:51)(cid:70)(cid:77)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84)(cid:73)(cid:74)(cid:81)(cid:84)(cid:1)(cid:88)(cid:74)(cid:85)(cid:73)(cid:1)

strategic contractors.
(cid:116)(cid:1)(cid:51)(cid:70)(cid:87)(cid:74)(cid:70)(cid:88)(cid:1)(cid:80)(cid:71)(cid:1)(cid:66)(cid:68)(cid:85)(cid:74)(cid:87)(cid:74)(cid:85)(cid:74)(cid:70)(cid:84)(cid:1)

investment review.

(cid:116)(cid:1)(cid:51)(cid:80)(cid:84)(cid:79)(cid:70)(cid:71)(cid:85)(cid:15)

in Azerbaijan, Caspian
and Turkey.

Risk

(cid:116)(cid:1)(cid:40)(cid:83)(cid:80)(cid:86)(cid:81)(cid:1)(cid:83)(cid:74)(cid:84)(cid:76)(cid:1)(cid:81)(cid:83)(cid:80)(cid:68)(cid:70)(cid:84)(cid:84)(cid:15)
(cid:116)(cid:1)Geopolitical risk.
(cid:116)(cid:1)(cid:37)(cid:70)(cid:77)(cid:74)(cid:87)(cid:70)(cid:83)(cid:90)(cid:1)(cid:80)(cid:71)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:18)(cid:17)(cid:14)(cid:81)(cid:80)(cid:74)(cid:79)(cid:85)(cid:1)

plan.

(cid:116)(cid:1)(cid:42)(cid:69)(cid:70)(cid:79)(cid:85)(cid:74)(cid:109)(cid:68)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)

allocation of risks to the
board and committees
for 2015.

Finance and
planning

Reputation

(cid:116)(cid:1)(cid:40)(cid:83)(cid:80)(cid:86)(cid:81)(cid:1)(cid:109)(cid:79)(cid:66)(cid:79)(cid:68)(cid:74)(cid:66)(cid:77)(cid:1)(cid:80)(cid:86)(cid:85)(cid:77)(cid:80)(cid:80)(cid:76)(cid:15)
(cid:116)(cid:1)(cid:50)(cid:86)(cid:66)(cid:83)(cid:85)(cid:70)(cid:83)(cid:77)(cid:90)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:71)(cid:86)(cid:77)(cid:77)-year

(cid:116)(cid:1)(cid:19)(cid:17)(cid:18)(cid:22)(cid:1)(cid:81)(cid:77)(cid:66)(cid:79)(cid:15)
(cid:116)(cid:1)(cid:52)(cid:73)(cid:66)(cid:83)(cid:70)(cid:73)(cid:80)(cid:77)(cid:69)(cid:70)(cid:83)(cid:1)(cid:69)(cid:74)(cid:84)(cid:85)(cid:83)(cid:74)(cid:67)(cid:86)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84)(cid:15)

results.

(cid:116)(cid:1)Annual Report and Form

20-F 2013 and 2014.

(cid:116)(cid:1)(cid:38)(cid:78)(cid:81)(cid:77)(cid:80)(cid:90)(cid:70)(cid:70)(cid:1)(cid:71)(cid:70)(cid:70)(cid:69)(cid:67)(cid:66)(cid:68)(cid:76)(cid:1)

survey.

(cid:116)(cid:1)(cid:35)(cid:49)(cid:1)(cid:67)(cid:83)(cid:66)(cid:79)(cid:69)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:72)(cid:77)(cid:80)(cid:67)(cid:66)(cid:77)(cid:1)

reputation.

(cid:116)(cid:1)(cid:42)(cid:79)(cid:87)(cid:70)(cid:84)(cid:85)(cid:80)(cid:83)(cid:1)(cid:66)(cid:86)(cid:69)(cid:74)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:48)(cid:85)(cid:73)(cid:70)(cid:83)(cid:1)(cid:74)(cid:79)(cid:87)(cid:70)(cid:84)(cid:85)(cid:80)(cid:83)(cid:1)(cid:71)(cid:70)(cid:70)(cid:69)(cid:67)(cid:66)(cid:68)(cid:76)(cid:15)

Board
development

(cid:116)(cid:1)(cid:35)(cid:80)(cid:66)(cid:83)(cid:69)(cid:1)(cid:70)(cid:87)(cid:66)(cid:77)(cid:86)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:15)(cid:1)
(cid:116)(cid:1)(cid:36)(cid:80)(cid:69)(cid:70)(cid:1)(cid:80)(cid:71)(cid:1)(cid:68)(cid:80)(cid:79)(cid:69)(cid:86)(cid:68)(cid:85)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)

(cid:116)(cid:1)(cid:55)(cid:74)(cid:84)(cid:74)(cid:85)(cid:84)(cid:1)(cid:85)(cid:80)(cid:1)(cid:34)(cid:91)(cid:70)(cid:83)(cid:67)(cid:66)(cid:74)(cid:75)(cid:66)(cid:79)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)
the Whiting reﬁnery.

BP values.

(cid:116)(cid:1)(cid:34)(cid:40)(cid:46)(cid:1)(cid:71)(cid:70)(cid:70)(cid:69)(cid:67)(cid:66)(cid:68)(cid:76)(cid:15)

Risk and assurance
During the year the board, either directly or 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 was also assessed (see Internal Control Revised
Guidance for Directors (Turnbull) on page 63).

The annual plan, group risk reviews and strategy are central to BP’s risk
management programme. They provide a framework by which the board
can consider principal 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 the audit, SEEAC and Gulf of Mexico committees)
monitored the group risks which were allocated following the board’s
review of the annual plan at the end of 2013.

Those group risks reviewed by the board during 2014 included risks
associated with the delivery of BP’s 10-point plan and geopolitical risk
associated with BP’s operations around the world. 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 board’s
monitoring committees (the audit, SEEAC 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 pages 64-71.

For 2015, the group risks allocated for review by the board include
geopolitical risk and the delivery of major projects★, particularly in the
Upstream. Further information on BP’s system of risk management is
outlined in Our management of risk on page 46.

BP Annual Report and Form 20-F 2014

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 ﬁeld visits to operations. The induction also covers
governance, duties of directors, the work of the board committees
generally and speciﬁcally the committees that a director will join.

To help develop an understanding of BP’s business, the board continues to
build its knowledge through brieﬁngs and ﬁeld visits. In 2014 the board
received training on BP’s code of conduct and brieﬁngs on key business
developments and changes to the UK Corporate Governance Code. The
board met local management and external stakeholders at its board
meetings in Istanbul and Chicago.

Non-executive directors are expected to attend at least one ﬁeld visit per
year. In 2014 the board visited the Whiting reﬁnery in the US and members
of the SEEAC visited BP’s operations in Baku and Brazil. After each visit,
the board or appropriate committee was briefed on the impressions gained
by the directors during the visit.

Board visit to the Whiting reﬁnery

Ahead of its meeting in Chicago, the board visited the Whiting reﬁnery.

Directors met the reﬁnery’s leadership team as well as staff and
contractors on-site. They got a ﬁrst-hand view of progress on the Whiting
reﬁnery modernization project and an opportunity to see existing
operations.
As well as seeing the application of BP’s OMS★ at the reﬁnery, the board
also heard details of the role the reﬁnery plays in delivering results for
North America Fuels and the wider BP group.

Board evaluation
Each year BP undertakes a review of the board, its committees and
individual directors. The chairman’s performance is evaluated by the
chairman’s committee.

In 2014, an internally designed board evaluation for the board and the
committees was carried out using a questionnaire prepared by an external
facilitator (Lintstock). The evaluation tested key areas of the board’s work
including strategy, business performance, risk and governance processes.
The output of the committee reviews were discussed individually at each
committee meeting in December 2014. The output of the board review
was used as the basis for one-to-one interviews between each director
and the chairman. Results of the board evaluation and feedback from these
interviews were discussed by the board in January 2015.

Key conclusions from the evaluation
The evaluation, which considered the work of the board and its
committees, concluded that the processes of the board had worked well.
The evaluation focused on how the board would continue to ensure that it
was discussing the right issues and that, overall the board was adding
value.

Reports from the business and on major projects were in very good shape.
On the rapidly shifting economic and geopolitical climate, the board was
keen to ensure that it manages its time to allow appropriate levels of
discussion. The need to balance its monitoring activities with discussion on
strategic matters was recognized and ought to be continually borne in
mind. The future role of technology in delivering BP’s strategy was
highlighted.

Follow up from our previous evaluation
Following the 2013 evaluation, more agenda time was allocated to the
development of strategy and governance around capital projects, resulting
in the creation of a regular performance report on the group’s major
projects. The board also had a detailed brieﬁng on the group’s view on
long-term technology trends and examined organizational capability,
including diversity and inclusion, at one of its strategic days.

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★ Defined on page 252.

BP Annual Report and Form 20-F 2014

Private investors
BP held a further event for private investors in conjunction with the UK
Shareholders’ Association (UKSA) in 2014. The chairman and head of
investor relations made presentations on BP’s annual results, strategy and
the work of the board. The shareholders asked questions on BP’s
activities. Later in the year, the UKSA met with the company to give
feedback on the BP Strategic Report 2013.

AGM
Voting levels decreased slightly in 2014 to 63.13% (of issued share capital,
including votes cast as withheld), compared to 64.24% in 2013 and
63.24% in 2012. Each year the board receives a report after the AGM
giving a breakdown of the votes and investor feedback on their voting
decisions for the meeting to inform the board on any issues arising.

UK Corporate Governance Code compliance
BP complied throughout 2014 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).

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 those
directors who met with shareholders over the year.

Shareholder engagement cycle 2014

January

February

March

April

June

July

August

September

October

December

BP Energy Outlook 2035 presentation

Fourth quarter results
Investor roadshows with executive management

Strategy update presentation to investors
Chairman and board committee chairs meeting
Engagement on remuneration
and governance issues
UKSA private shareholders’ meeting
SRI updates – unconventional gas
and hydraulic fracturing; and oil sands
SRI roadshow on BP Sustainability Review 2013

US legal issues conference call
Annual General Meeting
First quarter results

Launch of BP Statistical Review of World Energy

Second quarter results
Publication of the ‘BP proposition’ on bp.com
Investor roadshows with the group CEO
and CFO
Engagement with UKSA private shareholder
panel on BP’s 2013 ﬁnancial reports
US legal issues conference call
Oil and gas sector conferences

Third quarter results

Engagement on remuneration
Group SRI meeting
Upstream strategy presentation

Institutional investors
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
audit and remuneration committees held individual investor meetings to
discuss strategy, the board’s view on BP’s performance, governance, audit
and remuneration. An annual investor event was held in March 2014 with
the chairman and all the board committee chairs. 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.

In December the chairman and members of the executive team met with
socially responsible investors as part of BP’s annual SRI meeting. The
meeting examined a number of operational and strategic issues, including
how the board looks at risk and strategy, BP’s Energy Outlook 2035,
how the company approaches operational risk, upstream contractor
management, technology and BP’s portfolio.

See bp.com/investors to download materials from investor presentations,
including the group’s ﬁnancial results and information on the work of the
board and its committees.

BP Annual Report and Form 20-F 2014

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, with
one meeting held jointly with the main board. Between meetings IAB
members remain on hand to provide advice and counsel when needed.

The IAB is chaired by BP’s previous chairman, Peter Sutherland. Its
membership in 2014 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 emerging geopolitical issues which
could impact BP’s business, developments in Russia, the Middle East and
North Africa, the liberalization of Mexico’s oil and gas sector and the US
mid-term election cycle.

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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.

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 2014 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 2015 reviewed a report from the group head of
audit as part of the board’s annual review of the risk management and
internal control systems. The report described the annual summary of
group 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, group
head of audit 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.

★ Defined on page 252.

BP Annual Report and Form 20-F 2014

(cid:116)(cid:1) 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.

(cid:116)(cid:1) 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.

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, and is chairman of the group audit committee of The
Royal Bank of Scotland Group plc, and a member of the Financial Reporting
Council Monitoring Committee. He was president of the Institute of
Chartered Accountants of Scotland in 2013. 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
representatives of the external auditor, who also meet with the committee
chair on a regular basis outside the meetings.

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 director responsibilities
for assurance over joint ventures, trends and developments in the use of
third-party agents and developments in global accounting standards.

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 accounting policies and judgements.

In conjunction with the SEEAC, the committee examined whether the
BP Annual Report and Form 20-F 2014 was fair, balanced and
understandable and provided the information necessary for shareholders
to assess the group’s performance, business model and strategy. The
committees recommended that the board could make the statement as
set out in the statement of directors’ responsibilities on page 90.

Committee reports

Audit committee

Chairman’s introduction
The work of the audit committee in 2014 remained focused on the
appropriateness of BP’s ﬁnancial reporting and accounting judgements, the
review of key group-level risks and the rigour of BP’s audit processes,
system of internal control and risk management. A number of key topics
have remained core to the committee’s agenda, including regular
assessment of the group’s ﬁnancial responsibilities arising from the
Deepwater Horizon accident and judgement on whether the group has
maintained signiﬁcant inﬂuence over Rosneft.

Outside these core areas, the committee undertook detailed reviews of key
areas of BP’s business, most notably in trading where the committee visited
the trading ﬂoors in London and Chicago. This allowed the committee to see
the role trading plays in the group’s broader business and its system of
governance, control, risk and compliance. Over the year, formal business of
the committee was supplemented by private meetings with key
constituents. These include BP’s group audit function, the group ethics and
compliance ofﬁcer and the external auditor. I believe the background and
experience of 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
(cid:116)(cid:1) Monitoring and obtaining assurance that the management or mitigation

of ﬁnancial risks are appropriately addressed by the group chief
executive and that the system of internal control 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.

(cid:116)(cid:1) Reviewing ﬁnancial statements and other ﬁnancial disclosures and
monitoring compliance with relevant legal and listing requirements.

(cid:116)(cid:1) Reviewing the effectiveness of the group audit function and BP’s
internal ﬁnancial controls and systems of internal control and risk
management.

BP Annual Report and Form 20-F 2014

Accounting judgements and estimates

Areas of signiﬁcant judgement considered by the committee during the year and how these were addressed included:

Accounting for
interests in other
entities

Oil and natural gas
accounting

Key issues/judgements in ﬁnancial reporting

Audit committee review

BP exercises judgement when assessing the level of control
obtained in a transaction to acquire an interest in another
entity, and, on an ongoing basis in assessing whether there
have been any changes in the level of control.

The committee continued to review the accounting for BP’s
investment in Rosneft including the assessment of signiﬁcant
inﬂuence in light of developments during the year, such as the
imposition of US and EU sanctions.

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.

Recoverability of asset
carrying values

Determining 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.

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.

Gulf of Mexico oil spill

Judgement was applied during the year around the provisions
and contingencies relating to the incident.

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.

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 judgemental aspects of oil and gas
accounting as part of the company’s quarterly due-diligence
process, including the treatment of certain intangible assets.
The committee considered the judgements made in
assessing the exploration write-offs recorded during the year.
It received a brieﬁng on the measurement of reserves and
also examined the group’s oil and gas reserves disclosures
that appear in this BP Annual Report and Form 20-F 2014.

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, particularly in light of the decline in prices in the latter
part of the year. The committee considered the judgements
made in assessing the existence of indicators of impairment of
assets as well as the signiﬁcant estimates made in the
measurement of the impairment losses recognized. The
committee also continued to discuss periodically with
management the recoverability of overdue receivables.

The committee received brieﬁngs on the group’s
decommissioning, environmental remediation and litigation
provisioning, including key assumptions used, discount rates
and the movement in provisions over time.

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The committee regularly discussed the provisioning for and
the disclosure of contingent liabilities relating to the Gulf of
Mexico oil spill with management, external auditors and
external counsel, including as part of the review of BP’s stock
exchange announcement at each quarter end. The committee
examined developments relating to US court rulings (including
Clean Water Act penalties, business and economic loss
settlement payments and natural resource damages) and
monitored legal developments while considering the impact
on the ﬁnancial statements and other disclosures.

The committee examined the assumptions used by
management as part of its annual reporting process.

The committee reviewed the judgements exercised on tax
provisioning as part of its annual review of key provisions.

BP Annual Report and Form 20-F 2014

Audit committee focus in 2014

(cid:116)(cid:1)(cid:39)(cid:74)(cid:79)(cid:66)(cid:79)(cid:68)(cid:74)(cid:66)(cid:77)(cid:1)(cid:83)(cid:70)(cid:84)(cid:86)(cid:77)(cid:85)(cid:84)(cid:1)(cid:66)(cid:79)(cid:79)(cid:80)(cid:86)(cid:79)(cid:68)(cid:70)(cid:78)(cid:70)(cid:79)(cid:85)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:34)(cid:79)(cid:79)(cid:86)(cid:66)(cid:77)(cid:1)(cid:51)(cid:70)(cid:81)(cid:80)(cid:83)(cid:85)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:39)(cid:80)(cid:83)(cid:78)(cid:1)(cid:19)(cid:17)(cid:14)(cid:39)(cid:15)
(cid:116)(cid:1)(cid:34)(cid:68)(cid:68)(cid:80)(cid:86)(cid:79)(cid:85)(cid:74)(cid:79)(cid:72)(cid:1)(cid:75)(cid:86)(cid:69)(cid:72)(cid:70)(cid:78)(cid:70)(cid:79)(cid:85)(cid:84)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:70)(cid:84)(cid:85)(cid:74)(cid:78)(cid:66)(cid:85)(cid:70)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:1)(cid:37)(cid:70)(cid:87)(cid:70)(cid:77)(cid:80)(cid:81)(cid:78)(cid:70)(cid:79)(cid:85)(cid:84)(cid:1)(cid:74)(cid:79)(cid:1)(cid:109)(cid:79)(cid:66)(cid:79)(cid:68)(cid:74)(cid:66)(cid:77)(cid:1)(cid:83)(cid:70)(cid:81)(cid:80)(cid:83)(cid:85)(cid:74)(cid:79)(cid:72)

and accounting.

(cid:116)(cid:1)(cid:48)(cid:74)(cid:77)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:72)(cid:66)(cid:84)(cid:1)(cid:83)(cid:70)(cid:84)(cid:70)(cid:83)(cid:87)(cid:70)(cid:84)(cid:1)(cid:69)(cid:74)(cid:84)(cid:68)(cid:77)(cid:80)(cid:84)(cid:86)(cid:83)(cid:70)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:39)(cid:66)(cid:74)(cid:83)(cid:13)(cid:1)(cid:67)(cid:66)(cid:77)(cid:66)(cid:79)(cid:68)(cid:70)(cid:69)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:86)(cid:79)(cid:69)(cid:70)(cid:83)(cid:84)(cid:85)(cid:66)(cid:79)(cid:69)(cid:66)(cid:67)(cid:77)(cid:70)(cid:15)(cid:11)

(cid:116)(cid:1)(cid:51)(cid:70)(cid:87)(cid:74)(cid:70)(cid:88)(cid:1)(cid:80)(cid:71)(cid:1)(cid:70)(cid:71)(cid:71)(cid:70)(cid:68)(cid:85)(cid:74)(cid:87)(cid:70)(cid:79)(cid:70)(cid:84)(cid:84)(cid:1)(cid:80)(cid:71)(cid:1)(cid:35)(cid:49)(cid:8)(cid:84)(cid:1)(cid:84)(cid:90)(cid:84)(cid:85)(cid:70)(cid:78)(cid:1)
of internal control and risk management.*

(cid:116)(cid:1)(cid:40)(cid:83)(cid:80)(cid:86)(cid:81)(cid:1)(cid:66)(cid:86)(cid:69)(cid:74)(cid:85)(cid:1)(cid:83)(cid:70)(cid:81)(cid:80)(cid:83)(cid:85)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:39)(cid:83)(cid:66)(cid:86)(cid:69)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:78)(cid:74)(cid:84)(cid:68)(cid:80)(cid:79)(cid:69)(cid:86)(cid:68)(cid:85)(cid:1)(cid:83)(cid:70)(cid:81)(cid:80)(cid:83)(cid:85)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:38)(cid:85)(cid:73)(cid:74)(cid:68)(cid:84)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:68)(cid:80)(cid:78)(cid:81)(cid:77)(cid:74)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:83)(cid:70)(cid:81)(cid:80)(cid:83)(cid:85)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:34)(cid:79)(cid:79)(cid:86)(cid:66)(cid:77)(cid:1)(cid:70)(cid:85)(cid:73)(cid:74)(cid:68)(cid:84)(cid:1)(cid:68)(cid:70)(cid:83)(cid:85)(cid:74)(cid:109)(cid:68)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:15)(cid:11)

* Undertaken jointly with the SEEAC.

Financial
disclosure

System of internal
control and risk
management

External
audit

Risk
reviews

(cid:116)(cid:1)(cid:36)(cid:80)(cid:79)(cid:109)(cid:83)(cid:78)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:1)(cid:80)(cid:71)(cid:1)(cid:70)(cid:89)(cid:85)(cid:70)(cid:83)(cid:79)(cid:66)(cid:77)(cid:1)(cid:66)(cid:86)(cid:69)(cid:74)(cid:85)(cid:80)(cid:83)(cid:1)

independence.

(cid:116)(cid:1)(cid:47)(cid:80)(cid:79)(cid:14)(cid:66)(cid:86)(cid:69)(cid:74)(cid:85)(cid:1)(cid:71)(cid:70)(cid:70)(cid:84)(cid:1)(cid:111)(cid:1)(cid:81)(cid:80)(cid:77)(cid:74)(cid:68)(cid:90)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:66)(cid:81)(cid:81)(cid:83)(cid:80)(cid:87)(cid:66)(cid:77)(cid:15)
(cid:116)(cid:1)(cid:34)(cid:86)(cid:69)(cid:74)(cid:85)(cid:1)(cid:81)(cid:77)(cid:66)(cid:79)(cid:13)(cid:1)(cid:71)(cid:70)(cid:70)(cid:84)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:70)(cid:79)(cid:72)(cid:66)(cid:72)(cid:70)(cid:78)(cid:70)(cid:79)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:34)(cid:86)(cid:69)(cid:74)(cid:85)(cid:80)(cid:83)(cid:1)(cid:81)(cid:70)(cid:83)(cid:71)(cid:80)(cid:83)(cid:78)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:70)(cid:71)(cid:71)(cid:70)(cid:68)(cid:85)(cid:74)(cid:87)(cid:70)(cid:79)(cid:70)(cid:84)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:44)(cid:70)(cid:90)(cid:1)(cid:66)(cid:83)(cid:70)(cid:66)(cid:84)(cid:1)(cid:80)(cid:71)(cid:1)(cid:75)(cid:86)(cid:69)(cid:72)(cid:70)(cid:78)(cid:70)(cid:79)(cid:85)(cid:1)(cid:71)(cid:80)(cid:83)(cid:1)(cid:90)(cid:70)(cid:66)(cid:83)-end audit.
(cid:116)(cid:1)(cid:34)(cid:86)(cid:69)(cid:74)(cid:85)(cid:1)(cid:85)(cid:70)(cid:79)(cid:69)(cid:70)(cid:83)(cid:74)(cid:79)(cid:72)(cid:15)

(cid:116)(cid:1)(cid:36)(cid:90)(cid:67)(cid:70)(cid:83)(cid:84)(cid:70)(cid:68)(cid:86)(cid:83)(cid:74)(cid:85)(cid:90)(cid:15)
(cid:116)(cid:1)(cid:53)(cid:83)(cid:66)(cid:69)(cid:74)(cid:79)(cid:72), compliance and control.
(cid:116)(cid:1)(cid:36)(cid:80)(cid:78)(cid:81)(cid:77)(cid:74)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:88)(cid:74)(cid:85)(cid:73)(cid:1)(cid:67)(cid:86)(cid:84)(cid:74)(cid:79)(cid:70)(cid:84)(cid:84)(cid:1)(cid:83)(cid:70)(cid:72)(cid:86)(cid:77)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84).
(cid:116)(cid:1)(cid:53)(cid:66)(cid:89)(cid:15)
(cid:116)(cid:1)(cid:38)(cid:71)(cid:71)(cid:70)(cid:68)(cid:85)(cid:74)(cid:87)(cid:70)(cid:79)(cid:70)(cid:84)(cid:84)(cid:1)(cid:80)(cid:71)(cid:1)(cid:74)(cid:79)(cid:87)(cid:70)(cid:84)(cid:85)(cid:78)(cid:70)(cid:79)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:45)(cid:74)(cid:82)(cid:86)(cid:74)(cid:69)(cid:74)(cid:85)(cid:90)(cid:15)
(cid:116)(cid:1)(cid:40)(cid:80)(cid:74)(cid:79)(cid:72)(cid:1)(cid:68)(cid:80)(cid:79)(cid:68)(cid:70)(cid:83)(cid:79)(cid:15)

The effectiveness of the audit process was evaluated through a survey of
the committee and those impacted by the audit. It used a set of criteria to
measure the auditors’ performance against the quality commitment set
out in their annual audit plan. This related to both the quality of opinion
and of service. This included the robustness of the audit process,
independence and objectivity, quality of delivery, quality of people and
service and value added advice. The 2014 evaluation concluded that there
was a good quality audit process and that the external auditors were
regarded as technically knowledgeable and unafraid to challenge and
intervene where necessary. Areas of suggested focus for the auditors
included audit team turnover and the identiﬁcation of risk areas for audit
focus. 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 its 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. It
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 taking into account the UK Corporate Governance Code,
the EU Audit Regulation 2014 and the Statutory Audit Service Order 2014,
order issued by the UK Competitions and Markets Authority. Having
considered the impact of these regimes, the committee concluded that
the best interests of the group and its shareholders would be served by
utilizing the transition arrangements outlined by the Financial Reporting
Council in relation to the governance code 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.

Risk reviews
The group risks allocated to the audit committee for monitoring in 2014
included those associated with trading activities, compliance with applicable
laws and regulations and security threats against BP’s digital infrastructure.
The committee held in-depth reviews of these group risks over the year. It
also examined the group’s governance of the tax function and its approach
to tax planning and reviewed how risk is assessed and considered when
evaluating BP’s capital investment 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 reviewed 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 signiﬁcant allegations and investigations and on key ethics and
compliance issues. Further joint meetings were held with the SEEAC to
discuss the annual certiﬁcation report of compliance with the BP code of
conduct and the role and remit of the newly formed business integrity
function. The two committees also met to discuss the group audit and
ethics and compliance programmes for 2014. The committee held a private
meeting with the group ethics and compliance ofﬁcer during the year.

External audit
The external auditors started the annual cycle with their audit strategy
which identiﬁed key risks to be monitored during the year – including the
provisions and contingencies related to the Gulf of Mexico oil spill, the
impact of the estimation of the quantity of oil and gas reserves and
resources on impairment testing, depreciation, depletion and amortization
and decommissioning provisions, unauthorized trading activity and BP’s
ability to maintain signiﬁcant inﬂuence over Rosneft and consequently our
ability to recognize our share of Rosneft’s income, production and
reserves. The committee received updates during the year on the audit
process, including how the auditors had challenged the group’s
assumptions on these issues.

The audit committee reviews the fee structure, resourcing and terms of
engagement for the external auditor annually. Fees paid to the external
auditor for the year were $53 million, of which 8% was for non-assurance
work (see Financial statements – Note 34). Non-audit or non-audit related
assurance fees were $5 million (2013 $5 million). 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.

BP Annual Report and Form 20-F 2014

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
auditor is only considered for permitted non-audit services when its
expertise and experience of the company is important. A two-tier system
operates for approval of audit-related and non-audit work. 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 a case-by-case 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 2014 the committee used an online survey which
examined governance issues such as committee processes and support,
the work of the committee and priorities for change.

Areas of focus for 2015 arising from the evaluation included the inclusion of
broader segment and business reviews, undertaking more deep dive
reviews and suggestions for further committee training.

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 services

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.

Other services

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.

Non-permitted services
SEC principles of auditor independence

Bookkeeping/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.

Public Company Accounting Oversight Board (PCAOB) ethics and
independence rules

Contingent fees.
Conﬁdential or aggressive tax position transactions.

Tax services for persons in ﬁnancial reporting oversight roles.

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BP Annual Report and Form 20-F 2014

In addition to the committee membership, all the SEEAC meetings were
attended by the group chief executive, the executive vice president for safety
and operational risk and the general auditor or his delegate. The external
auditor attended some of the meetings (and was briefed on the other
meetings by the chair and secretary to the committee), as did the group
general counsel and group ethics and compliance ofﬁcer. 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

Alan Boeckmann Member since September 2014

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 marine, wells, pipelines, facilities and major
security incidents. The committee reviewed these risks, and risk
management and mitigation, in depth with 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. We were pleased that Mr Sandlin agreed, at the
committee’s request, to extend his engagement to the summer of 2016.
He reported twice directly to the SEEAC in 2014, and presented detailed
reports on his work, including reporting on a number of visits made to
group operations around the world. He also reported to the committee that
25 out of 26 recommendations in the Bly Report were completed by the
end of 2014 (and he will report to the committee regarding the ﬁnal
recommendation which is expected to be completed at the end of 2015).

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 included the committee receiving speciﬁc reports on BP’s
management of high priority risks in marine, wells, pipelines, facilities and
major security incidents. The committee also undertook a number of ﬁeld
visits as well as maintained its schedule of regular meetings with executive
management.

We continued to receive regular reports from the independent experts that
we have engaged in 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.

We were also very pleased to welcome Alan Boeckmann to the
committee in September. Alan brings valuable experience and insight from
his many years at Fluor.

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 as
well as cross-business information from the functions. These include, but
are not limited to, the safety and operational risk (S&OR) 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 six times in 2014, 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 63). 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.

BP Annual Report and Form 20-F 2014

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SEEAC focus in 2014

(cid:116)(cid:1)Group chief executive’s operations risk reports.
(cid:116)(cid:1)(cid:50)(cid:86)(cid:66)(cid:83)(cid:85)(cid:70)(cid:83)(cid:77)(cid:90)(cid:1)(cid:83)(cid:70)(cid:81)(cid:80)(cid:83)(cid:85)(cid:84)(cid:1)(cid:80)(cid:79)(cid:1)(cid:41)(cid:52)(cid:38)(cid:1)(cid:81)(cid:70)(cid:83)(cid:71)(cid:80)(cid:83)(cid:78)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:80)(cid:81)(cid:70)(cid:83)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:66)(cid:77)(cid:1)

integrity.

(cid:116)(cid:1)(cid:52)(cid:86)(cid:84)(cid:85)(cid:66)(cid:74)(cid:79)(cid:66)(cid:67)(cid:74)(cid:77)(cid:74)(cid:85)(cid:90)(cid:1)reporting annual overview.
(cid:116)(cid:1)(cid:39)(cid:66)(cid:74)(cid:83)(cid:13)(cid:1)(cid:67)(cid:66)(cid:77)(cid:66)(cid:79)(cid:68)(cid:70)(cid:69)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:86)(cid:79)(cid:69)(cid:70)(cid:83)(cid:84)(cid:85)(cid:66)(cid:79)(cid:69)(cid:66)(cid:67)(cid:77)(cid:70)(cid:15)(cid:11)
(cid:116)(cid:1)(cid:39)(cid:74)(cid:70)(cid:77)(cid:69)(cid:1)(cid:85)(cid:83)(cid:74)(cid:81)(cid:84)(cid:1)(cid:77)(cid:70)(cid:69)(cid:1)(cid:67)(cid:90)(cid:1)the SEEAC (including visits to

Azerbaijan and Brazil biofuels).

internal control and risk management.*

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(cid:116)(cid:1)(cid:50)(cid:86)(cid:66)(cid:83)(cid:85)(cid:70)(cid:83)(cid:77)(cid:90)(cid:1)(cid:84)(cid:74)(cid:72)(cid:79)(cid:74)(cid:109)(cid:68)(cid:66)(cid:79)(cid:85)(cid:1)(cid:66)(cid:77)(cid:77)(cid:70)(cid:72)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)

investigations reports.

(cid:116)(cid:1)(cid:50)(cid:86)(cid:66)(cid:83)(cid:85)(cid:70)(cid:83)(cid:77)(cid:90)(cid:1)ethics and compliance reports.
(cid:116)(cid:1)(cid:34)(cid:79)(cid:79)(cid:86)(cid:66)(cid:77)(cid:1)(cid:70)(cid:85)(cid:73)(cid:74)(cid:68)(cid:84)(cid:1)(cid:68)(cid:70)(cid:83)(cid:85)(cid:74)(cid:109)(cid:68)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:15)(cid:11)

* Undertaken jointly with the audit committee.

Monitoring of
operations and
reporting

System of internal
control and risk
management

External and
internal audit

Risk reviews

(cid:116)(cid:1)(cid:38)(cid:89)(cid:85)(cid:70)(cid:83)(cid:79)(cid:66)(cid:77)(cid:1)(cid:66)(cid:86)(cid:69)(cid:74)(cid:85)(cid:80)(cid:83)(cid:1)(cid:66)(cid:84)(cid:84)(cid:86)(cid:83)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:80)(cid:71)(cid:1)

sustainability reporting.

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internal control.

(cid:116)(cid:1)(cid:52)(cid:7)(cid:48)(cid:51)(cid:1)(cid:66)(cid:86)(cid:69)(cid:74)(cid:85)(cid:1)(cid:66)(cid:84)(cid:84)(cid:86)(cid:83)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:9)(cid:66)(cid:84)(cid:1)(cid:81)(cid:66)(cid:83)(cid:85)(cid:1)(cid:80)(cid:71)(cid:1)(cid:72)(cid:83)(cid:80)(cid:86)(cid:81)(cid:1)

audit).

(cid:116)(cid:1)(cid:38)(cid:89)(cid:81)(cid:77)(cid:80)(cid:84)(cid:74)(cid:80)(cid:79)(cid:1)(cid:80)(cid:83)(cid:1)(cid:83)(cid:70)(cid:77)(cid:70)(cid:66)(cid:84)(cid:70)(cid:1)(cid:66)(cid:85)(cid:1)(cid:71)(cid:66)(cid:68)(cid:74)(cid:77)(cid:74)(cid:85)(cid:74)(cid:70)(cid:84)(cid:15)
(cid:116)(cid:1)Major security incident (terrorism).
(cid:116)(cid:1)(cid:56)(cid:70)(cid:77)(cid:77)(cid:1)(cid:74)(cid:79)(cid:68)(cid:74)(cid:69)(cid:70)(cid:79)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:49)(cid:74)(cid:81)(cid:70)(cid:77)(cid:74)(cid:79)(cid:70)(cid:1)(cid:74)(cid:79)(cid:68)(cid:74)(cid:69)(cid:70)(cid:79)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:46)(cid:66)(cid:83)(cid:74)(cid:79)(cid:70)(cid:1)(cid:74)(cid:79)(cid:68)(cid:74)(cid:69)(cid:70)(cid:79)(cid:85)(cid:15)

Process safety expert – Downstream
Mr Duane Wilson continued to report to the committee in his role as
process safety expert for the Downstream segment. 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 lessons learned across the segment. He twice reported
directly to the SEEAC in 2014 and presented detailed reports on his work
(including reporting on a number of visits he has made to reﬁneries and
other downstream facilities). Mr Wilson will complete his engagement in
April 2015 and delivered his ﬁnal report to the SEEAC in January 2015. The
committee wishes to thank him for all of his work during the course of his
engagement and believes he has made a lasting and positive impact on the
process safety culture in the Downstream segment.

Reports from group audit and group ethics and compliance
The committee received quarterly reports from both of these functions.
These included summaries of investigations into signiﬁcant alleged fraud or
misconduct (which are now undertaken through the business integrity
team established in 2014). 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 May the chairman and other members of the committee visited Baku in
Azerbaijan to examine both offshore facilities (Central Azeri platform) and
the onshore gas reception terminal (Sangachal) operated by the group. In
October the chairman and another committee member visited operations
at the biofuels business in central Brazil. In September all members of the
committee visited the Whiting reﬁnery in Indiana, US, as part of a larger
board visit. In all cases, the visiting committee members received brieﬁngs
on operations, the status of local OMS implementation, and risk
management and mitigation. Committee members then reported back in
detail about each visit to the committee and subsequently to the board. In
addition the local management team reported back to the committee
regarding the status of the issues raised during the visit.

Committee review
For its 2014 evaluation, the SEEAC examined its performance and
effectiveness with a questionnaire administered by external consultants.
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

its work, in particular by giving committee members the ability to examine
how risk management is being embedded in businesses and facilities,
including management culture.

Gulf of Mexico committee

Chairman’s introduction
The Gulf of Mexico committee continues to oversee the group’s response
to the Deepwater Horizon accident, ensuring that BP fulﬁls all its legitimate
obligations while 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 (MDL) 2179 and 2185, 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 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. Its work is integrated with that of the board,
which retains ultimate accountability for oversight of the group’s response to
the accident.

BP Annual Report and Form 20-F 2014

Gulf of Mexico committee focus in 2014

(cid:116)(cid:1)(cid:46)(cid:37)(cid:45)(cid:1)(cid:19)(cid:18)(cid:24)(cid:26)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:19)(cid:18)(cid:25)(cid:22)(cid:15)
(cid:116)(cid:1)(cid:47)(cid:66)(cid:85)(cid:86)(cid:83)(cid:66)(cid:77)(cid:1)(cid:83)(cid:70)(cid:84)(cid:80)(cid:86)(cid:83)(cid:68)(cid:70)(cid:1)(cid:69)(cid:66)(cid:78)(cid:66)(cid:72)(cid:70)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:52)(cid:86)(cid:84)(cid:81)(cid:70)(cid:79)(cid:84)(cid:74)(cid:80)(cid:79)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:69)(cid:70)(cid:67)(cid:66)(cid:83)(cid:78)(cid:70)(cid:79)(cid:85)(cid:1)(cid:66)(cid:68)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84)(cid:15)
(cid:116)(cid:1)Impact on ﬁnancial reporting.
(cid:116)(cid:1)(cid:36)(cid:77)(cid:66)(cid:74)(cid:78)(cid:84)(cid:1)(cid:66)(cid:69)(cid:78)(cid:74)(cid:79)(cid:74)(cid:84)(cid:85)(cid:83)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:15)
(cid:116)(cid:1)(cid:48)(cid:85)(cid:73)(cid:70)(cid:83)(cid:1)(cid:77)(cid:74)(cid:85)(cid:74)(cid:72)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:74)(cid:79)(cid:87)(cid:70)(cid:84)(cid:85)(cid:74)(cid:72)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:15)

(cid:116)(cid:1)(cid:38)(cid:89)(cid:85)(cid:70)(cid:83)(cid:79)(cid:66)(cid:77)(cid:1)(cid:66)(cid:71)(cid:71)(cid:66)(cid:74)(cid:83)(cid:84)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:68)(cid:80)(cid:78)(cid:78)(cid:86)(cid:79)(cid:74)(cid:85)(cid:90)(cid:1)(cid:80)(cid:86)(cid:85)(cid:83)(cid:70)(cid:66)(cid:68)(cid:73)(cid:15)
(cid:116)(cid:1)(cid:54)(cid:52)(cid:1)(cid:72)(cid:80)(cid:87)(cid:70)(cid:83)(cid:79)(cid:78)(cid:70)(cid:79)(cid:85)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:78)(cid:70)(cid:69)(cid:74)(cid:66)(cid:1)(cid:68)(cid:80)(cid:78)(cid:78)(cid:86)(cid:79)(cid:74)(cid:68)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:42)(cid:79)(cid:85)(cid:70)(cid:83)(cid:79)(cid:66)(cid:77)(cid:1)(cid:68)(cid:80)(cid:78)(cid:78)(cid:86)(cid:79)(cid:74)(cid:68)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84)(cid:15)(cid:1)
(cid:116)(cid:1)(cid:45)(cid:74)(cid:68)(cid:70)(cid:79)(cid:68)(cid:70)(cid:1)(cid:85)(cid:80)(cid:1)(cid:80)(cid:81)(cid:70)(cid:83)(cid:66)(cid:85)(cid:70)(cid:15)

(cid:116)(cid:1)(cid:51)(cid:70)(cid:84)(cid:81)(cid:80)(cid:79)(cid:84)(cid:70)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:83)(cid:70)(cid:78)(cid:70)(cid:69)(cid:74)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:1)(cid:66)(cid:68)(cid:85)(cid:74)(cid:87)(cid:74)(cid:85)(cid:74)(cid:70)(cid:84)(cid:15)
(cid:116)(cid:1)(cid:47)(cid:66)(cid:85)(cid:86)(cid:83)(cid:66)(cid:77)(cid:1)(cid:83)(cid:70)(cid:84)(cid:80)(cid:86)(cid:83)(cid:68)(cid:70)(cid:1)(cid:69)(cid:66)(cid:78)(cid:66)(cid:72)(cid:70)(cid:84)(cid:1)(cid:66)(cid:84)(cid:84)(cid:70)(cid:84)(cid:84)(cid:78)(cid:70)(cid:79)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:51)(cid:70)(cid:84)(cid:85)(cid:80)(cid:83)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:1)(cid:81)(cid:83)(cid:80)(cid:75)(cid:70)(cid:68)(cid:85)(cid:84)(cid:15)

Legal

Operational

Reputation

Compliance

(cid:116)(cid:1)(cid:37)(cid:70)(cid:81)(cid:66)(cid:83)(cid:85)(cid:78)(cid:70)(cid:79)(cid:85)(cid:1)(cid:80)(cid:71)(cid:1)(cid:43)(cid:86)(cid:84)(cid:85)(cid:74)(cid:68)(cid:70)(cid:1)(cid:81)(cid:77)(cid:70)(cid:66)(cid:1)(cid:66)(cid:72)(cid:83)(cid:70)(cid:70)(cid:78)(cid:70)(cid:79)(cid:85)(cid:15)
(cid:116)(cid:1)(cid:52)(cid:38)(cid:36)(cid:1)(cid:68)(cid:80)(cid:79)(cid:84)(cid:70)(cid:79)(cid:85)(cid:1)(cid:80)(cid:83)(cid:69)(cid:70)(cid:83)(cid:15)

Committee review
Each year the Gulf of Mexico committee evaluates its performance and
effectiveness. 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 for focus in 2015
included maintaining constructive and challenging engagement with
management as well as continuing timely and effective communication of
its activities and ﬁndings to the board.

Key responsibilities
(cid:116)(cid:1) 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.

(cid:116)(cid:1) 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.

(cid:116)(cid:1) Oversee management strategy and actions to restore the group’s

reputation in the US.

(cid:116)(cid:1) Review compliance with government settlement agreements arising out

of the Deepwater Horizon accident and oil spill, including the SEC
Consent Order, the Department of Justice plea agreement and the EPA
administrative agreement, in co-ordination 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

Alan Boeckmann Member since September 2014

The chairman and the group chief executive attend all meetings of the
committee.

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. Active clean-up activities are now complete in all states.

The committee continued to oversee numerous legal matters relating to
the Deepwater Horizon accident, including the ruling made in respect of
Phase 1 of the trial in MDL 2179 (and the subsequent appeal of that ruling),
preparation for the penalty phase of the trial and BP’s appeals to the US
Court of Appeals for the Fifth Circuit and the US Supreme Court relating to
the Court Supervised Settlement Program.

The committee met 11 times in 2014.

BP Annual Report and Form 20-F 2014

Nomination and chairman’s committees

Chairman’s introduction
I am pleased to report on the two board committees that 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 the company secretary.

Key responsibilities
(cid:116)(cid:1) Identify, evaluate and recommend candidates for appointment or

reappointment as directors.

(cid:116)(cid:1) Identify, evaluate and recommend candidates for appointment as

company secretary.

The committee considered the feedback from its own evaluation. There
were several actions including a greater focus on executive succession and
the interaction between the chairman’s and nomination committee in this
respect. The committee also wishes to make agenda time to consider
broader issues such as succession and diversity. Future searches for
non-executive directors should generally focus on industry expertise and
also consider the split between former chief executive ofﬁcers and
directors with others skills on the board.

Chairman’s committee
Role of the committee
To provide a forum for matters to be discussed among the non-executive
directors.

Key responsibilities
(cid:116)(cid:1) Evaluate the performance and the effectiveness of the group chief

executive.

(cid:116)(cid:1) Review the structure and effectiveness of the business organization.
(cid:116)(cid:1) Review the systems for senior executive development and determine

the succession plan for the group chief executive, the executive
directors and other senior members of executive management.
(cid:116)(cid:1) Determine any other matter that is appropriate to be considered

by all of the non-executive directors.

(cid:116)(cid:1) 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 during the year
The committee met ﬁve times in the year to:

(cid:116)(cid:1) Assess the effect of sanctions on Russia on BP’s relationship

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(cid:116)(cid:1) Keep under review the mix of knowledge, skills and experience of the

with Rosneft.

board to ensure the orderly succession of directors.

(cid:116)(cid:1) Review the outside directorship/commitments of the non-executive

(cid:116)(cid:1) Monitor the progress of the Gulf of Mexico litigation.
(cid:116)(cid:1) Determine the framework for board evaluation in 2015.
(cid:116)(cid:1) Review the background to the 2015 plan in light of the decline

in oil prices.

(cid:116)(cid:1) Consider the chief executive’s plans for the succession and organization

directors.

Members

Name

Membership status

of the executive team.

(cid:116)(cid:1) Evaluate the performance of the chairman and chief executive.

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

Ian Davis

Member since May 2011

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 six times during the year.

It continued to reﬂect on the rhythm of the meetings. As in 2013, the
committee held one longer meeting during the year and reviewed board
composition and skills in light of BP’s strategy.

In 2014 the committee considered the sequencing of board retirements
over the coming years and potential board candidates. It is pursuing several
promising individuals and appointments are likely to be made in 2015. As
part of this, letters of appointment for all non-executive directors were
reviewed and amended. The committee considered the chairmanship and
membership of each committee. As a result it was agreed that Dame
Professor Ann Dowling would take the chair of the remuneration
committee when Antony Burgmans steps down from that role in 2015, and
that Andrew Shilston and Alan Boeckmann will join the remuneration
committee after the 2015 annual general meeting.

BP Annual Report and Form 20-F 2014

Directors’ remuneration report

Chairman’s annual statement

We are responding to these concerns and are committed to making as full
a retrospective disclosure of those targets that we are able to, subject to
conﬁdentiality. I believe that this is demonstrated in this year’s report,
particularly in the tables relating to annual bonus and performance shares.
In terms of overall quantum of remuneration, I have previously made clear
that the committee understands the concerns felt in society and by some
shareholders. The committee, however, believes that these concerns are
properly recognized and balanced in the way in which the policy is framed
and implemented.

At the time of our last report, the outcome for the performance shares was
based on an estimated second place for relative reserves replacement.
Once results for the oil majors were publicly available it was assessed that
BP was in ﬁrst place, resulting in a vesting of 45.5%. The awards were
adjusted and announced accordingly.

Finally, in July, Iain Conn agreed with the board that he would stand down
as a director on 31 December 2014. Iain has made a signiﬁcant
contribution to the company over his long career and, on this basis, the
terms of his departure were agreed with the committee within the policy.
The terms were promptly communicated on BP’s website and are set out
again later in this report.

2014 outcomes

BP has performed well in increasingly difﬁcult circumstances. This has
been demonstrated by the delivery of the 10-point plan, which the board
approved as BP’s strategic direction in 2011. In considering performance in
2014 and its effect on remuneration, two areas stand out. Firstly, a key
milestone in delivery of the plan was achieving $32.8 billion of operating
cash ﬂow . The excellent performance in this measure had a strong
inﬂuence on both the annual bonus and the performance share element.
The second area with an equally strong inﬂuence was safety. Over the
three years of the performance share element, performance improved by
more than 15% on two of the measures and over 60% on one measure.

Annual bonus

Measures for the annual bonus that focused on safety and value were
largely unchanged from previous years to encourage continuity of
performance and delivery. There had been a strong safety performance in
2013. We seek continuous improvement in this area and the targets for
2014 were ambitious. Against that background, performance was mixed
and showed a modest improvement.

Operating cash stood out as being well ahead of target but underlying
replacement cost proﬁt★ was below. Seven projects started up in 2014,
making 16 major projects★ start-ups since the beginning of 2012. All of
this resulted in a group performance score of 1.10, compared with a score
of 1.32 last year. The committee felt that this score reasonably reﬂected
the overall performance for the year. Following elections by the executive
directors, one third of this bonus will be paid in cash and two thirds in
shares that are deferred for three years and matched. There is
retrospective disclosure of many of the targets for the annual bonus later in
this report.

Deferred bonus

2011 deferred bonus share awards became eligible for vesting at the end
of 2014. Vesting is dependent on safety and environmental sustainability
performance over that period. The committee reviewed this in consultation
with the SEEAC. Based on strong and consistent improvement and no
signiﬁcant incidents, the deferred and matching shares vested in full.

Dear shareholder,
2014 started strongly but, as others have commented in this report, ended
more turbulently as the price of oil fell, mainly in the last quarter. This
formed the backdrop for the decisions of the committee at the end of
2014. The work of the committee is governed by a number of overriding
principles. Key among these is seeking a fair outcome in reward that is
linked to BP’s immediate and long-term performance and strategy delivery.
As part of this, the committee seeks to ensure that variable remuneration
is based on underlying performance and is not driven by factors over which
the directors have no control. All of this work is carried out within the policy
framework that was approved overwhelmingly by shareholders earlier in
the year.

In this context:

(cid:116)(cid:1) 2014 saw the end of an improving three-year period for BP. This is

demonstrated elsewhere in the report. The high-performance gearing in
remuneration of the executive directors reﬂects good business results
through an overall increase in remuneration compared to last year.

(cid:116)(cid:1) The world is a more uncertain place in 2015. BP has responded broadly
to this, including freezing salaries, and the committee has refocused the
measures for the annual bonus to reﬂect new challenges.

(cid:116)(cid:1) There are clear concerns in society and among shareholders that

remuneration for executive directors is simply too much. The policy,
now approved by shareholders, is clear and recognizes these concerns
particularly by placing limits on the amounts that can be awarded.
Equally, this remuneration has to be appropriate to be aligned with the
global market for talent in which BP works. Here the committee has to
strike a balance.

2014 in retrospect

Our remuneration policy was approved at the 2014 AGM for a three-year
period. At the same meeting, a number of shareholders voted against or
withheld their votes on our annual remuneration report. There were several
reasons for this. There were concerns around our commitment to
disclosure of targets, whether prospectively or retrospectively, and the
need for additional disclosure when the committee was exercising
judgements around qualitative measures. Some shareholders believed that
the overall remuneration of the executive directors was excessive.

BP Annual Report and Form 20-F 2014

Performance shares

The 2012-2014 performance share plan was, as in the previous year, based
on three sets of measures equally weighted; relative total shareholder
return (TSR), operating cash ﬂow and ﬁnally strategic imperatives, which
include relative reserves replacement ratio (RRR), safety and operational
risk and rebuilding trust. The committee made its assessment of
performance over the three-year period against the agreed targets and its
view of the achievements over that time. There were no shares awarded
for TSR as the minimum threshold was not reached. As I have mentioned
above, there was strong performance against the safety measures and the
committee exercised its judgement based on qualitative data in respect of
the need to rebuild trust. As for 2013, the assessment was preliminary as
the ﬁnal results from the comparator group for RRR were not available. On
the basis of information available, second place was recorded. Based on
this preliminary assessment, 60.5% of the shares are expected to vest.
The committee believes that this represents a fair outcome for a
continually improving performance over the period. Again, there is
retrospective disclosure of many of the targets used for the 2012-2014
performance share plan in this report.

2015 and the future
During 2014, BP set out a clear proposition to shareholders aimed at
delivering value rather than volume through active portfolio management,
growing sustainable free cash ﬂow through capital discipline and growing
distributions for shareholders. The company’s key performance indicators
(KPIs) are designed to measure performance against this proposition. The
committee is determined that the remuneration of the directors remains
clearly linked to the company’s strategy. There has been a refocus of some
of the measures for the 2015 annual bonus to reﬂect this and the current
short-term imperatives facing BP. The graphic below sets out BP’s
strategic priorities and links them to the measures used for short and long
term remuneration with further detail in this report.

Previously, the committee reviewed the executive directors’ salaries in
May each year. In future, it will do so in January for implementation in April,
at the same time as the rest of the organization. Given the general company
pay freeze, no salary increases were awarded to directors for 2015.

Policy issues
In 2014, the UK Corporate Governance Code was revised. The Code
introduced, on a ‘comply or explain’ basis, a requirement to introduce
malus and clawback provisions into all performance related elements of
directors’ remuneration. The committee has reviewed the terms of the
executive directors’ remuneration and conﬁrmed that malus and clawback
provisions exist in all terms save the cash element of the annual bonus. It
will propose an appropriate provision on the next occasion that it renews
the remuneration policy. The committee also undertook a detailed
examination of its tasks. The changes that have been made are set out in
more detail later in this report.

Conclusion
Whilst BP has performed well in recent years and momentum has been
building, there are clearly more challenging times ahead. We have set out
our approach in this changing world. It is likely that, within our policy, we
will need to exercise judgement and discretion based on solid data. Should
we be required to do so, it will be done within our policy and with
subsequent disclosure so that our shareholders are clear on the decisions
that we have taken.

Finally, I will be standing down as the chair of the committee in June and I
will be succeeded by Professor Dame Ann Dowling. Ann has sat on the
committee after joining the board in 2012 and I look forward to introducing
her to our shareholders. I would like to thank our shareholders for the
support, and the challenge, over the past four years.

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Antony Burgmans
Chairman of the remuneration committee
3 March 2015

Strategic priorities

Grow our
exploration
position

Focus on
high-value
upstream
assets

Quality portfolio
Build high-quality
downstream businesses

Advanced
technology

Distinctive capabilities

Proven
expertise

Strong
relationships

Safe, reliable and
compliant operations

Clear priorities

Competitive
project
execution

Disciplined
ﬁnancial
choices

2015 bonus and equity plans supporting BP’s strategic priorities

Short-term: annual bonus

Safety and operational risk

Long-term: performance share plan

Safety and operational risk

Operating cash ﬂow

Underlying replacement
cost proﬁt

Net investment (organic)

Total shareholder return

Major projects delivery

Corporate and functional costs

Major projects delivery

Reserves replacement

Creating long-term shareholder value

Group key performance indicator. Safety and operational risk KPIs include loss of primary containment, tier 1 process safety events★ and recordable
injury frequency.

Defined on page 252.

BP Annual Report and Form 20-F 2014

Remuneration committee report
The committee was made up of the following independent
non-executive directors in 2014.

Members

Antony Burgmans (chairman)

George David

Ian Davis

Professor Dame Ann Dowling

In addition, Carl-Henric Svanberg and Bob Dudley normally attend the
meetings except for matters relating to their own remuneration.

Key responsibilities
The committee’s tasks were reviewed during the year and are as follows:

(cid:116)(cid:1) Determine the policy for the chairman and the executive directors (the

policy) for inclusion in the remuneration policy for all directors as required
by the regulations.

(cid:116)(cid:1) Review and determine as appropriate the terms of engagement,

remuneration and termination of employment of the chairman and the
executive directors in accordance with the policy, and be responsible for
compliance with all remuneration issues relating to the chairman and the
executive directors required by the regulations.

group. Neither he, nor the chairman of the board, participate in decisions
on their own remuneration. The group human resources director normally
attends, and other executives may attend relevant parts of meetings.

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
During 2014 David Jackson, the company secretary, who is employed by
the company and reports to the chairman of the board, acted as secretary
to the remuneration committee. The company secretary periodically
reviews the independence of the committee’s advisers.

Gerrit Aronson, an independent consultant, is the committee’s
independent adviser. He is engaged directly by the committee. He advises
the chairman, the board and the nomination committee on a variety of
governance issues. Advice and services on particular remuneration
matters were also 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 2014 to the
above advisers for the provision of remuneration advice to the committee
as set out above (save in respect of legal advice) are as follows:

(cid:116)(cid:1) Prepare for the board an annual report to shareholders on the

implementation of the policy, so far as it relates to the chairman and the
executive directors, as required by the regulations.

Gerrit Aronson £140,000

Towers Watson £23,400

(cid:116)(cid:1) Approve the principles of any equity plan for which shareholder approval

is to be sought.

(cid:116)(cid:1) Approve the terms of the remuneration (including pension and

termination arrangements) of the executive team as proposed by the
group chief executive (GCE).

Activities during the year
During the year, the committee met ﬁve times. Key discussions and
decision items are shown in the table below.

Remuneration committee 2014 meetings

Jan May

Jul

Sept Dec

(cid:116)(cid:1) Approve changes to the design of remuneration as proposed by the

GCE, for the group leaders of the company.

Strategy and policy

(cid:116)(cid:1) Monitor implementation of remuneration for group leaders to ensure

alignment and proportionality.

(cid:116)(cid:1) Engage such independent consultants or other advisers as the

committee may from time to time deem necessary, at the expense of
the company.

In these tasks regulations shall mean regulations made under the
Companies Act 2006 from time to time in relation to the remuneration of
directors of quoted companies, the UK Corporate Governance Code
adopted by the Financial Reporting Council from time to time and the UK
Listing Authority’s Listing Rules from time to time.

Committee review and composition
The board evaluation process included a separate questionnaire on the work
of the remuneration committee. The results were analysed by an external
consultant and discussed at the committee’s meeting in December 2014.
Processes continued to be rated as good to excellent and a number of
topics for more in-depth discussion were identiﬁed. In particular the
committee decided to schedule a longer strategy meeting each year.

George David stands down from the board at the next annual general
meeting and will leave the committee. Alan Boeckmann and Andrew
Shilston will join the committee after that meeting.

Professor Dame Ann Dowling will take the chair of the committee in June
2015. Antony Burgmans will remain a member of the committee.

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 GCE is consulted on the remuneration of the other executive directors
and the executive team and on matters relating to the performance of the

BP Annual Report and Form 20-F 2014

Review and approve DRR for 2014 AGM

Review and approve EDIP for 2014 AGM

Consider DRR votes from 2014 AGM

Review committee tasks and operation

Salary review

Executive directors

Executive team and leadership group

Annual bonus

Assess performance

Determine bonus for 2013

Agree measures and targets for 2014

Review measures for 2015

Consider measures and targets for 2015

Long-term equity plan

Assess performance

Determine vesting of 2011-2013 plan

Determine vesting of 2010 deferred bonus

Agree measures, targets and awards
for 2014-2016 plan

Review measures for 2015-2017 plan
Consider measures and targets
for 2015-2017 plan

Other items

Review principles for target setting
and disclosure
Other issues as required

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Executive directors
Total remuneration summary 2014
Salary – reviewed mid-year and increased by an average of 3% for all
directors – this was in line with average employee increases in the UK and
US.

Annual bonus – the key focus for 2014 was delivery of the group’s
10-point plan, strong operating cash ﬂow, safe and reliable operations and
delivery of major projects within the year. Operating cash ﬂow exceeded
planned targets. Overall safety results were satisfactory and consolidated
the improvements made over the last three years. The underlying
operating performance was strong. Overall group score was 1.10 times
target.

Deferred bonus – 2011 deferred bonus was conditional on safety and
environmental sustainability performance over the period 2012 through to

2014. There was strong and consistent delivery against this hurdle and
2011 deferred and matched shares vested in full.

Performance shares – vesting was based one third on relative total
shareholder return (TSR), one third on operating cash ﬂow and one third on
strategic imperatives including safety and operational risk (S&OR), relative
reserves replacement ratio (RRR) and rebuilding trust internally and
externally. TSR performance did not achieve the minimum level necessary
for this part of the award to vest. There was strong operating cash ﬂow.
There was similarly strong performance against the strategic imperatives.
On a preliminary assessment 60.5% of the 2012-2014 award are
expected to vest.

Pension – pension ﬁgures reﬂect the UK requirements to show 20 times
the increase in accrued pension over the year for deﬁned beneﬁt plans, as
well as any cash paid in lieu.

Single ﬁgure table of remuneration of executive directors in 2014 (audited)

Annual remuneration 2014
Salary
Annual cash bonusa
Beneﬁts
Total

Vested equity
Deferred bonus and matchb
Performance shares
Total

Total remuneration
Pension
Pension value increasee
Cash in lieu of future accrual
Total including pension

Remuneration is reported in the currency received by the individual

Bob Dudley
thousand

Dr Brian Gilvary
thousand

Iain Conn
thousand

2014
$1,827
$1,005
$114
$2,946

2013
$1,776
$2,344
$90
$4,210

2014
£721
£396
£51
£1,168

2013
£700
£924
£45
£1,669

2014
£786
£1,252
£55
£2,093

2013
£763
£961
£59
£1,783

$3,401
$6,391c
$9,792

$5,963d
$5,963

£0
£1,904c
£1,904

£0
£505
£505

£1,698
£2,014c
£3,712

£242
£1,688d
£1,930

$12,738

$10,173

£3,072

£2,174

£5,805

£3,713

$2,596
N/A
$15,334

$4,447
N/A
$14,620

£21
£252
£3,345

£44
£245
£2,463

£18
£275
£6,098

£46
£267
£4,026

a This reﬂects the amount of bonus paid in cash with the deferred portion as set out in the conditional equity table below. In the case of Iain Conn, there was no deferral of bonus and all bonus was paid

in cash.

b Value of vested deferred bonus and matching shares. The amounts reported for 2014 relate to the 2011 annual bonus deferred over three years, which vested on 11 February 2015 at the market price of

$40.35 and £4.46 and include re-invested dividends on shares vested. The amounts reported for 2013 relate to the 2010 annual bonus.

c Represents the assumed vesting of shares in 2015 following the end of the relevant performance period, based on a preliminary assessment of 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 2014 which was £4.27
for ordinary shares and $40.74 for ADSs. The ﬁnal vesting will be conﬁrmed by the committee in second quarter 2015 and provided in the 2015 Directors’ remuneration report.

d In accordance with UK regulations, in the 2013 single ﬁgure table, the performance outcome value was based on an estimated vesting at an assumed share price of £4.69 for ordinary shares and

$45.52 for ADSs. In May 2014, after the external data became available, the committee reviewed the relative reserves replacement ratio position and assessed that the group was ﬁrst place relative to
the other oil majors. This resulted in an adjustment to the ﬁnal vesting from 39.5% to 45.5%. On 15 May 2014, 115,766 ADSs for Bob Dudley and 331,330 shares for Iain Conn vested at prices of
$50.90 and £5.03 respectively. The vesting of the ﬁnal notional dividends prior to the vesting date took place on 24 June 2014 when Bob Dudley received 1,331 ADSs and Iain Conn received 4,122
shares at prices of $52.84 and £5.24 respectively. The 2013 values for the total vesting have increased by $1,440,954 for Bob Dudley and £356,604 for Iain Conn.

e Represents the annual increase net of inﬂation in accrued pension multiplied by 20 as prescribed by UK regulations.

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
Release datea

Value (thousand)

Performance share element
Potential maximum shares
Vesting date
Release date

Bob Dudley

Dr Brian Gilvary

Iain Conn

2014
$2,010
294,108
294,108
Feb 2018
Feb 2021

2014
2013
£793
$1,172
176,576
149,628
176,576
149,628
Feb 2018
Feb 2017
Feb 2020 Feb 2021

2013
£462
96,653
96,653
Feb 2017
Feb 2020

2014
–
–
–
–
–

2013
£481
100,563
100,563
Feb 2017
Feb 2018

2014-2016

2014-2016
2013-2015
605,544
1,304,922 1,384,026
Feb 2017
Feb 2017
Feb 2016
Feb 2019 Feb 2020
Feb 2020

2013-2015
637,413
Feb 2016
Feb 2019

2014-2016
220,043b
Feb 2017
Feb 2018

2013-2015
463,126b
Feb 2016
Feb 2017

a Deferred shares are released at vesting with the exception of matched shares which normally have a further three-year retention period.
b Potential maximum of performance shares element has been pro-rated to reﬂect actual service during the performance period.

BP Annual Report and Form 20-F 2014

Total remuneration in more depth
In describing the work and decisions of the committee in 2014, the
summary wording of the approved policy has been used to introduce the
committee’s approach to each element of remuneration. Throughout this
report, the word policy refers to the directors’ remuneration policy

approved by shareholders at the company’s annual general meeting on 10
April 2014. BP’s strategy is reﬂected in the measures adopted by the
committee for the executive directors and further aligned with those for
the senior leadership of the group. The policy is available at
bp.com/remuneration and is set out in the BP Annual Report and
Form 20-F 2013.

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.

Policy summary

Operation and opportunity

(cid:116)(cid:1) (cid:52)(cid:66)(cid:77)(cid:66)(cid:83)(cid:74)(cid:70)(cid:84)(cid:1)(cid:66)(cid:83)(cid:70)(cid:1)(cid:79)(cid:80)(cid:83)(cid:78)(cid:66)(cid:77)(cid:77)(cid:90)(cid:1)(cid:84)(cid:70)(cid:85)(cid:1)(cid:74)(cid:79)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:73)(cid:80)(cid:78)(cid:70)(cid:1)(cid:68)(cid:86)(cid:83)(cid:83)(cid:70)(cid:79)(cid:68)(cid:90)(cid:1)(cid:80)(cid:71)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:70)(cid:89)(cid:70)(cid:68)(cid:86)(cid:85)(cid:74)(cid:87)(cid:70)(cid:1)(cid:69)(cid:74)(cid:83)(cid:70)(cid:68)(cid:85)(cid:80)(cid:83)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:83)(cid:70)(cid:87)(cid:74)(cid:70)(cid:88)(cid:70)(cid:69)(cid:1)(cid:66)(cid:79)(cid:79)(cid:86)(cid:66)(cid:77)(cid:77)(cid:90)(cid:15)
(cid:116)(cid:1)

(cid:1)(cid:52)(cid:66)(cid:77)(cid:66)(cid:83)(cid:90)(cid:1)(cid:77)(cid:70)(cid:87)(cid:70)(cid:77)(cid:84)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:85)(cid:80)(cid:85)(cid:66)(cid:77)(cid:1)(cid:83)(cid:70)(cid:78)(cid:86)(cid:79)(cid:70)(cid:83)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:1)(cid:80)(cid:71)(cid:1)(cid:80)(cid:74)(cid:77)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:80)(cid:85)(cid:73)(cid:70)(cid:83)(cid:1)(cid:85)(cid:80)(cid:81)(cid:1)(cid:38)(cid:86)(cid:83)(cid:80)(cid:81)(cid:70)(cid:66)(cid:79)(cid:1)(cid:78)(cid:86)(cid:77)(cid:85)(cid:74)(cid:79)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:66)(cid:77)(cid:84)(cid:13)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:83)(cid:70)(cid:77)(cid:66)(cid:85)(cid:70)(cid:69)(cid:1)(cid:54)(cid:52)(cid:1)(cid:68)(cid:80)(cid:83)(cid:81)(cid:80)(cid:83)(cid:66)(cid:85)(cid:74)(cid:80)(cid:79)(cid:84)(cid:13)(cid:1)(cid:66)(cid:83)(cid:70)(cid:1)(cid:68)(cid:80)(cid:79)(cid:84)(cid:74)(cid:69)(cid:70)(cid:83)(cid:70)(cid:69)(cid:1)(cid:67)(cid:90)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:68)(cid:80)(cid:78)(cid:78)(cid:74)(cid:85)(cid:85)(cid:70)(cid:70)(cid:15)(cid:1)
Internally, increases for the group leaders as well as employees in relevant countries are considered.
(cid:1)(cid:52)(cid:66)(cid:77)(cid:66)(cid:83)(cid:90)(cid:1)(cid:74)(cid:79)(cid:68)(cid:83)(cid:70)(cid:66)(cid:84)(cid:70)(cid:84)(cid:1)(cid:88)(cid:74)(cid:77)(cid:77)(cid:1)(cid:67)(cid:70)(cid:1)(cid:74)(cid:79)(cid:1)(cid:77)(cid:74)(cid:79)(cid:70)(cid:1)(cid:88)(cid:74)(cid:85)(cid:73)(cid:1)(cid:66)(cid:77)(cid:77)(cid:1)(cid:70)(cid:78)(cid:81)(cid:77)(cid:80)(cid:90)(cid:70)(cid:70)(cid:1)(cid:74)(cid:79)(cid:68)(cid:83)(cid:70)(cid:66)(cid:84)(cid:70)(cid:84)(cid:1)(cid:74)(cid:79)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:54)(cid:44)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:54)(cid:52)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:77)(cid:74)(cid:78)(cid:74)(cid:85)(cid:70)(cid:69)(cid:1)(cid:85)(cid:80)(cid:1)(cid:88)(cid:74)(cid:85)(cid:73)(cid:74)(cid:79)(cid:1)(cid:19)(cid:6)(cid:1)(cid:80)(cid:71)(cid:1)(cid:66)(cid:87)(cid:70)(cid:83)(cid:66)(cid:72)(cid:70)(cid:1)(cid:74)(cid:79)(cid:68)(cid:83)(cid:70)(cid:66)(cid:84)(cid:70)(cid:1)(cid:71)(cid:80)(cid:83)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:72)(cid:83)(cid:80)(cid:86)(cid:81)(cid:1)(cid:77)(cid:70)(cid:66)(cid:69)(cid:70)(cid:83)(cid:84)(cid:15)
(cid:1)(cid:1)(cid:35)(cid:70)(cid:79)(cid:70)(cid:109)(cid:85)(cid:84)(cid:1)(cid:83)(cid:70)(cid:110)(cid:70)(cid:68)(cid:85)(cid:1)(cid:73)(cid:80)(cid:78)(cid:70)(cid:1)(cid:68)(cid:80)(cid:86)(cid:79)(cid:85)(cid:83)(cid:90)(cid:1)(cid:79)(cid:80)(cid:83)(cid:78)(cid:84)(cid:15)(cid:1)(cid:53)(cid:73)(cid:70)(cid:1)(cid:68)(cid:86)(cid:83)(cid:83)(cid:70)(cid:79)(cid:85)(cid:1)(cid:81)(cid:66)(cid:68)(cid:76)(cid:66)(cid:72)(cid:70)(cid:1)(cid:80)(cid:71)(cid:1)(cid:67)(cid:70)(cid:79)(cid:70)(cid:109)(cid:85)(cid:84)(cid:1)(cid:88)(cid:74)(cid:77)(cid:77)(cid:1)(cid:67)(cid:70)(cid:1)(cid:78)(cid:66)(cid:74)(cid:79)(cid:85)(cid:66)(cid:74)(cid:79)(cid:70)(cid:69)(cid:13)(cid:1)(cid:66)(cid:77)(cid:85)(cid:73)(cid:80)(cid:86)(cid:72)(cid:73)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:85)(cid:66)(cid:89)(cid:66)(cid:67)(cid:77)(cid:70)(cid:1)(cid:87)(cid:66)(cid:77)(cid:86)(cid:70)(cid:1)(cid:78)(cid:66)(cid:90)(cid:1)(cid:110)(cid:86)(cid:68)(cid:85)(cid:86)(cid:66)(cid:85)(cid:70)(cid:15)

(cid:116)(cid:1)
(cid:116)(cid:1)

Performance framework

(cid:116)(cid:1)

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salary increase and exceptional sustained contribution may be grounds for accelerated salary increases.

Base salary
The annual base salaries of the executive directors were reviewed in May
2014. In conducting this review the committee considered all of the factors
required by the policy and the overall level of increases for employees in
both the UK and the US. They also considered the distribution and average
level of increases for group leaders comprising around 500 executives in
the group. This averaged 3.1%. Based on this review, salaries were
increased by 3% on average, resulting in salaries of $1,854,000 for Bob
Dudley, £731,500 for Dr Brian Gilvary and £797,000 for Iain Conn. These
increases took effect on 1 July 2014.

2015 implementation
The committee determined that in future years, salaries would be
reviewed in January to be effective in April, consistent with the rest
of BP’s employees. No increases were granted for 2015, in line with the
group-wide salary freeze.

Beneﬁts
Executive directors received car-related beneﬁts, security assistance,
insurance and medical beneﬁts.

Annual bonus

Provides a variable level of remuneration dependent on short-term performance against the annual plan.

Policy summary

Operation and opportunity

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reﬂects BP’s strategy.
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nature of the measure in question.

Performance framework

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recordable injury frequency and tier 1 process safety events.
(cid:1)(cid:53)(cid:73)(cid:70)(cid:1)(cid:81)(cid:83)(cid:74)(cid:79)(cid:68)(cid:74)pal measures of annual bonus will be 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.

Value made up 70% of group annual bonus objectives. Measures included
delivering operating cash ﬂow in line with the 10-point plan; increasing
underlying replacement cost proﬁt; reducing corporate and functional
costs; improving operating efﬁciency in upstream operations by minimizing
unplanned deferrals; completing major projects planned within the year;
and delivering downstream proﬁt per barrel of reﬁning capacity.

Iain Conn’s annual bonus was based 70% against the group annual bonus
objectives and 30% against safety, operating efﬁciency and proﬁtability
performance of the downstream segment.

Framework
The committee determined performance measures and their weightings
for the 2014 annual bonus at the beginning of the performance year,
focusing on two key priorities: safety and value.

Performance measures remained largely unchanged from last year in order
to maintain continuity and build momentum for delivery of the 10-point
plan. Measures and targets reﬂected the business plan for the year and
were set so that meeting plan would result in an on target bonus reward.

Bob Dudley and Dr Brian Gilvary’s annual bonus was based 100% on
group annual bonus objectives.

Safety made up 30% of group annual bonus objectives. Safety measures
related to loss of primary containment, tier 1 process safety events and
recordable injury frequency. Challenging targets for these measures were
set, both to build on the improving trend of the last three years and to
continue to reduce the number of safety events.

BP Annual Report and Form 20-F 2014

Measures

Weight
On target
Maximum

Weighted
outcome %

Target
Met
Not met

Group key

performance
indicator

Plan/target

2014 outcomes
In January 2015, the committee considered the group’s performance during
2014 against the measures and targets set out below.

In safety, the committee recognized that ambitious targets had been set
and the improvements in the year varied between the measures. In loss of
primary containment, the improvement was above the threshold but below
the target resulting in a weighted score of 7.96 out of 10; similarly in
recordable injury frequency (RIF) the improvement was above the threshold
but below the target resulting in a weighted score of 6.07 out of 10.
Importantly, these levels of performance still represented an improvement
on the previous year. Tier 1 process safety events did not reach the
threshold expectation and therefore did not score. The outcomes relative to
these targets were mixed, however the underlying trend remained positive,
reﬂecting continued improvement over the past three years.

Operating cash ﬂow of $32.8 billion was well ahead of target of $30 billion.
Underlying replacement cost proﬁt of $12.1 billion was below target of
$14.5 billion. Through greater simpliﬁcation and efﬁciency across all
functions, corporate and functional costs were reduced by 9% against a

targeted reduction of 7%. In terms of operational performance seven major
projects were successfully delivered in 2014 against the plan of six.
Upstream unplanned deferrals were reduced by 6% against a targeted
reduction of 9%. Downstream net income per barrel of $4.4/bbl was below
target of $6.4/bbl.

Based on these results, the overall group performance score was 1.10.
The committee, as is its normal practice, considered this result in the
context of the underlying ﬁnancial performance of the group, competitors’
results, shareholder feedback and input from the board and other
committees. After review, it concluded that this result fairly represented the
overall performance of the business during the year.

In the downstream segment, safety results were good with improvements
in loss of primary containment and process safety tier 2 events. Operating
cash ﬂow was ahead of plan but reﬁning availability and net income per
barrel were below plan expectations. The performance score was 0.98.

A summary of the outcomes for each measure, set against the target for
the year, is shown below.

2014 annual cash bonus

Safety

Value

C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
n
c
e

Loss of
primary
containment

Tier 1
process
safety
eventsa

Recordable
injury
frequency

Operating
cash
ﬂowb

Underlying
replacement
cost proﬁtb

Corporate
and
functional
costs

Downstream
net income/
bblb

Major
project
delivery

Upstream
unplanned
deferrals

Total

10%
20%

7.96

10%
20%

Nil

10%
20%

6.07

16.33%
32.67%

32.67

13.78

28.26

7%
14%

4.77

7%
14%

10.50

7%
14%

5.95

100%
200%
110% =
score
1.10

32.67%

28.26%

7.96%

6.07%

13.78%

3-10% improvement

$30bn

$14.5bn

Outcome

246 events

28 events

0.307 per
200k hrs

$32.8bn

$12.1bn

4.77%

$6.4/bbl

$4.4/bbl

7%
reduction

9%
reduction

10.50%

6 project
start-ups

7 project
start-ups

5.95%

9%
reduction

6%
reduction

a Deﬁned by American Petroleum Institute (API).
b Assessment of the ﬁnancial outcomes was done using the same conditions as the targets were set at – oil price, reﬁning margin and other environmental factors were taken into account.

The overall bonus for directors was determined by multiplying the group
score of 1.10 times target by the on-target bonus level of 150% of salary.
Bob Dudley’s total overall bonus was 165% of salary, as was Dr Brian
Gilvary’s. Iain Conn’s total overall bonus was 159% of salary, based on
both group and downstream segment performance (accounting for 30% of
his bonus). Under the terms of the deferred element of the EDIP, one third
of the total bonus is paid in cash. A director is required to defer a further
third and the ﬁnal third is paid either in cash or voluntarily deferred at the
individual’s election.

Bob Dudley and Dr Brian Gilvary have both elected to defer the ﬁnal third of
their annual bonus. Iain Conn, who left at the end of the year, was not
eligible for deferral and so all his bonus (reﬂecting his 12 months of service)
was paid in cash. The following table outlines the amounts paid in cash and
amounts deferred into shares.

Annual bonus summary

Bob Dudley
Dr Brian Gilvary
Iain Conn

Overall bonus
$3,014,550
£1,189,238
£1,252,480

Paid in cash
$1,004,850
£396,413
£1,252,480

Deferred in BP shares
$2,009,700
£792,825
£0

BP Annual Report and Form 20-F 2014

2015 implementation
For 2015, 100% of Bob Dudley’s and Dr Brian Gilvary’s bonus will be
based on group results.

The 2015 bonus plan has been set in the context of recent group
achievements (delivery of the 10-point plan), current short-term
imperatives and the group’s strategy. The committee will continue to focus
on the two overall themes of safety and value. In order to focus on
priorities of the short term, the number of value measures has been
reduced from six in 2014 to ﬁve in 2015. The measures reﬂect the current
short term imperatives and tie back to the 2015 priorities in the group’s
annual plan. Targets for each measure are challenging but realistic and have
been set in the context of the current environment.

Continued improvement in safety remains a group priority and is fully
reﬂected in the measures. Safety will continue to have a 30% weight in the
overall bonus plan. The value measures are now more heavily weighted on
operating cash ﬂow and underlying replacement cost proﬁt. Capital and
cost discipline are reﬂected through two measures – net investment
(organic) and corporate and functional cost management. The delivery of
major projects remains a point of focus. All of these value measures are
key to short-term performance within the group and will have an overall
weight of 70% for the annual bonus 2015.

The committee agreed the performance measures for the 2015 annual
cash bonus as set out opposite.

Targets will be disclosed retrospectively in the 2015 remuneration report to
the extent that they are no longer considered commercially sensitive.

Deferred bonus

2015 annual bonus measures

Strategic priorities

Clear
priorities

Quality
portfolio

Distinctive
capabilities

Safety and operational risk 30%

Value 70%

Loss of primary containment 10%

Operating cash ﬂow 20%

Underlying replacement cost
proﬁt 20%

Process safety tier 1 events 10%

Net investment (organic) 15%

Recordable injury frequency 10%

Corporate and functional costs 10%

Major project delivery 5%

Creating long-term shareholder value

Reinforces the long-term nature of the business and the importance of sustainability, linking a further part of remuneration to equity.

Policy summary

Operation and opportunity

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(cid:1)(cid:34)(cid:1)(cid:85)(cid:73)(cid:74)(cid:83)(cid:69)(cid:1)(cid:80)(cid:71)(cid:1)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.
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the committee of safety and environmental sustainability over the three-year period.
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retention period.

Performance framework

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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.
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2014 outcomes
Both Bob Dudley and Iain Conn deferred two thirds of their 2011 annual
bonus in accordance with the terms of the policy in place at the time of
deferral.

The three-year performance period concluded at the end of 2014. The
committee reviewed safety and environmental sustainability performance
over this period and sought the input of the safety, ethics and environment
assurance committee (SEEAC). Over the three-year period 2012-2014
safety measures showed steady improvement. All performance hurdles
were met and the group-wide operating management system★ is now
sufﬁciently embedded throughout the organization to continue driving
improvement in environmental as well as safety areas.

Following the committee’s review, full vesting of the deferred and matched
shares for the 2011 deferred bonus was approved, as shown in the
following table (as well as in the single ﬁgure table on page 75).

2011 deferred bonus vesting

Name
Bob Dudley

Iain Conn

Shares
deferred
436,824

Total shares
including
Vesting
dividends
agreed
100% 505,782

Total
value
at vesting
$3,401,384

322,608

100% 380,785

£1,698,301

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 84.

Details of the deferred bonus awards made to the executive directors in
early 2014, in relation to 2013 annual bonuses, were set out in last year’s
report. A summary of these awards is included on page 84.

2015 implementation
The committee has determined that the safety and environmental
sustainability hurdle will continue to apply to shares deferred from the 2014
bonus. All matched shares that vest in 2018 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 in 2021. This further
reinforces long-term shareholder alignment and the nature of the group’s
business. Both Bob Dudley and Dr Brian Gilvary deferred two thirds of their
2014 annual bonus.

BP Annual Report and Form 20-F 2014

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.

Policy summary

Operation and opportunity

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can be awarded annually.
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period.

Performance framework

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(cid:1)(cid:1)(cid:46)(cid:70)(cid:66)(cid:84)(cid:86)(cid:83)(cid:70)(cid:84)(cid:1)(cid:67)(cid:66)(cid:84)(cid:70)(cid:69)(cid:1)(cid:80)(cid:79)(cid:1)(cid:83)(cid:70)(cid:77)(cid:66)(cid:85)(cid:74)(cid:87)(cid:70)(cid:1)(cid:81)(cid:70)(cid:83)(cid:71)(cid:80)(cid:83)(cid:78)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:85)(cid:80)(cid:1)(cid:80)(cid:74)(cid:77)(cid:1)(cid:78)(cid:66)(cid:75)(cid:80)(cid:83)(cid:84)(cid:1)(cid:88)(cid:74)(cid:77)(cid:77)(cid:1)(cid:87)(cid:70)(cid:84)(cid:85)(cid:1)(cid:18)(cid:17)(cid:17)(cid:6)(cid:13)(cid:1)(cid:25)(cid:17)(cid:6)(cid:13)(cid:1)(cid:19)(cid:22)(cid:6)(cid:1)(cid:71)(cid:80)(cid:83)(cid:1)(cid:109)(cid:83)(cid:84)(cid:85)(cid:13)(cid:1)(cid:84)(cid:70)(cid:68)(cid:80)(cid:79)(cid:69)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:85)(cid:73)(cid:74)(cid:83)(cid:69)(cid:1)(cid:81)(cid:77)(cid:66)(cid:68)(cid:70)(cid:1)(cid:109)(cid:79)(cid:74)(cid:84)(cid:73)(cid:1)(cid:83)(cid:70)(cid:84)(cid:81)(cid:70)(cid:68)(cid:85)(cid:74)(cid:87)(cid:70)(cid:77)(cid:90)(cid:1)(cid:66)(cid:79)(cid:69)(cid:1)(cid:17)(cid:6)(cid:1)(cid:71)(cid:80)(cid:83)(cid:1)
fourth or ﬁfth position.
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to be more aligned to strategic priorities. These are explained in the annual report on remuneration.
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performance of the company’s business or is inconsistent with shareholder beneﬁts.
(cid:1)(cid:34)(cid:77)(cid:77)(cid:1)(cid:81)(cid:70)(cid:83)(cid:71)(cid:80)(cid:83)(cid:78)(cid:66)(cid:79)(cid:68)(cid:70)(cid:1)(cid:84)(cid:73)(cid:66)(cid:83)(cid:70)(cid:84)(cid:1)(cid:66)(cid:83)(cid:70)(cid:1)(cid:84)(cid:86)(cid:67)(cid:75)(cid:70)(cid:68)(cid:85)(cid:1)(cid:85)(cid:80)(cid:1)(cid:68)(cid:77)(cid:66)(cid:88)(cid:67)(cid:66)(cid:68)(cid:76)(cid:1)(cid:81)(cid:83)(cid:80)(cid:87)(cid:74)(cid:84)(cid:74)(cid:80)(cid:79)(cid:84)(cid:1)(cid:74)(cid:71)(cid:1)(cid:85)(cid:73)(cid:70)(cid:90)(cid:1)(cid:66)(cid:83)(cid:70)(cid:1)(cid:71)(cid:80)(cid:86)(cid:79)(cid:69)(cid:1)(cid:85)(cid:80)(cid:1)(cid:73)(cid:66)(cid:87)(cid:70)(cid:1)(cid:67)(cid:70)(cid:70)(cid:79)(cid:1)(cid:72)(cid:83)(cid:66)(cid:79)(cid:85)(cid:70)(cid:69)(cid:1)(cid:80)(cid:79)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:67)(cid:66)(cid:84)(cid:74)(cid:84)(cid:1)(cid:80)(cid:71)(cid:1)(cid:78)(cid:66)(cid:85)(cid:70)(cid:83)(cid:74)(cid:66)(cid:77)(cid:77)(cid:90)(cid:1)(cid:78)(cid:74)(cid:84)(cid:84)(cid:85)(cid:66)(cid:85)(cid:70)(cid:69)(cid:1)(cid:109)(cid:79)(cid:66)(cid:79)(cid:68)(cid:74)(cid:66)(cid:77)(cid:1)(cid:80)(cid:83)(cid:1)
other data.

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Framework
Performance shares were conditionally awarded to each executive director
in 2012. Maximum awards under the policy were granted representing
ﬁve-and-a-half-times salary for Bob Dudley and four-times salary for
Dr Brian Gilvary and Iain Conn. Vesting of these awards was subject to
delivering targets set over the three-year performance period.

One third of the award was based on relative total shareholder return
(TSR), one third on operating cash ﬂow and one third on strategic
imperatives which were relative reserves replacement ratio (RRR), safety
and operational risk (S&OR) and rebuilding trust internally and externally, all
equally weighted. Again, performance against each of these measures
was designed to be aligned with group strategy, future direction and
creation of shareholder value.

Relative TSR represents the change in value of a BP shareholding between
the average of the fourth quarter of 2011 and the fourth quarter of 2014
compared to other oil majors (dividends are re-invested). RRR represents
organic reserves added over the three-year performance period divided by
the reserves extracted. This ratio is ranked against like-for-like organic RRR
for other oil major peers.

The 2012-2014 comparator group for relative TSR (33.3% weight) and
relative RRR (11.1% weight) was Chevron, ExxonMobil, Shell and Total.
The number of conditional shares that would vest for each of the relative
performance measures for ﬁrst, second and third place was set at the start
of 2012 and equals 100%, 70% and 35% respectively. This reﬂects the
approved rules applicable to the 2012-2014 plan. No shares would vest for
fourth or ﬁfth place.

For S&OR, percentage improvement targets were set. For rebuilding trust
measures, the committee determined that it would use qualitative and
quantitative data to assess the improvement of external and internal
perception of the group and to gauge whether trust was being rebuilt.
Judgement would then be exercised as appropriate.

2014 outcomes
The committee considered the performance of the group over the
three-year period of the plan and the speciﬁc achievements against each of
the targets set for the measures. Based on a preliminary assessment of
relative RRR, 60.5% of the shares awarded in the 2012-2014 plan are
expected to vest.

Relative TSR did not achieve the minimum required for any vesting. The
signiﬁcant weight associated with this measure (one third in total) aligns
the actual value delivered to executive directors with that to shareholders.

Operating cash ﬂow, representing a further one third of the award, was
$32.8 billion. This notably exceeded the target set in 2011 to increase
operating cash ﬂow by more than 50% between 2012 and 2014 at
$100/bbl. Consequently, maximum shares for this component will vest.

Strategic imperatives represented the ﬁnal third. These included relative
RRR, S&OR, and rebuilding trust internally and externally. These elements
are discussed individually below.

Preliminary assessment of BP’s relative RRR indicated a positive outcome
with a minimum expected second place amongst the comparator group.
The ﬁnal ranking will be determined once the actual results for 2014 have
been published by other comparator companies. For the purposes of this
report, and in accordance with the UK regulations, second place has been
assumed. Any adjustment to this will be reported in next year’s annual
report on remuneration. Based on a provisional second place assessment,
7.8% of the maximum of 11.1% shares are expected to vest for RRR.

S&OR has improved signiﬁcantly over the 2012-2014 period. Loss of
primary containment showed a reduction of 32%, the number of reported
work related incidents (RIFs) reduced by 15% and tier 1 process safety
events reduced by 62%. The underlying trend of continuing improvement
over the past three years has been very positive. Consequently, the
maximum of 11.1% shares will vest for the safety measures.

In 2011, shortly after the Deepwater Horizon incident, restoring trust both
externally and internally was an important priority for the group and, as
such, featured as one of the strategic imperatives of the plan. Since then,
external and internal trust has been measured by surveys conducted with
external audiences and internally with employees. External trust is tracked
through six indicators with key stakeholders in the US and UK. Over the
three years, external surveys showed improvements ranging from one to
six percent with different external audiences.

Employee engagement is assessed by an index which measures
employees’ perceptions of BP including understanding of business
priorities, trust in BP leaders and conﬁdence in BP’s future strategy. This
index has shown a four percent improvement since 2011 and a two
percent improvement since 2012 across different levels of the organization.

Defined on page 252.

BP Annual Report and Form 20-F 2014

The results of this index were benchmarked against external data and were
particularly encouraging.

Recognizing the need to make further progress in this area, the committee
determined that 8.3% of the maximum 11.1% of shares will vest for the
rebuilding trust measure.

As in past years, the committee also considered the overall performance of
the group during the period and whether any other factors should be taken
into account. Following this review, the committee assessed that a
preliminary 60.5% vesting was a fair reﬂection of the overall performance
pending conﬁrmation of the reserves replacement result. This will result in
the vesting shown in the table.

The vested shares for current executive directors are subject to a further
three-year retention period before they will be released to the individuals in
2018.

2012-2014 performance shares preliminary outcome

Bob Dudley

Dr Brian Gilvary

Iain Conn

Shares
awarded
1,343,712

Shares vested
inc dividends

Value of
vested shares
941,286 $6,391,332

624,434

660,633

445,912 £1,904,044

471,761 £2,014,419

The measures, targets and weight for the plan as well as, on a preliminary
basis, the outcomes achieved are shown below.

2012-2014 performance shares vesting

Measures

Weight at maximum

Outcome %

Relative total
shareholder
return

Operating
cash ﬂow

33.3%

Nil

33.3%

Relative
reserves
replacement
ratio

11.1%

7.8%

Safetya

11.1%

Rebuilding
trust

Total

11.1%

8.3%

100%

60.5%

33.3

Met
Not met

Group key performance indicator

Plan/target

7.8

11.1

8.3

Outperform
peers

$30bn

Outperform
peers

Improvement
10-15%

Improvement

Outcome
a Safety includes loss of primary containment, tier 1 process safety event (deﬁned by API) and recordable injury frequency.
b This represents a preliminary assessment.

$32.8bn

Secondb

Fifth

15-62%

Met

2011-2013 ﬁnal outcomes conﬁrmation
Last year it was reported that the committee had made a preliminary
assessment of second place for the relative RRR in the 2011-2013
performance shares element. In May 2014 the committee reviewed the
results for all comparator companies as published in their reports and
accounts and assessed that BP was in ﬁrst place relative to other oil majors
and that the full 20% of shares would vest for this performance measure
as opposed to 14% for second place. This resulted in a ﬁnal vesting of
45.5% from 39.5% for the entire award. This is reﬂected in the single
ﬁgure table on page 75.

2015 implementation
Shares were awarded in February 2015 to the maximum value allowed
under the policy, ﬁve-and-a-half-times salary for Bob Dudley and four-times
salary for Dr Brian Gilvary (see table on page 85). These have been
awarded under the performance share element of the EDIP and are
subject to a three-year performance period. Those shares that vest are
subject, after tax, to an additional three-year retention period. The
2015-2017 performance share element will be assessed over three years
based on the following measures: relative TSR (one third); cumulative
operating cash ﬂow (one third); and strategic imperatives (one third)
including relative RRR; S&OR risk assessment; and major project delivery.

2015-2017 performance shares

Strategic priorities

Clear
priorities

Quality
portfolio

Distinctive
capabilities

Total shareholder return 1/3

Cumulative operating cash ﬂow 1/3

Strategic priorities 1/3

Safety and operational risk

Reserves replacement

Major project delivery

Creating long-term shareholder value

BP Annual Report and Form 20-F 2014

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These measures continue to be aligned with BP’s strategic priorities of
safe, reliable and compliant operations, major project delivery, disciplined
ﬁnancial choices and growing our exploration position.

TSR and RRR will be assessed on a relative basis compared with the other
oil majors Chevron, ExxonMobil, Shell and Total with the following vesting
schedule.

The committee has agreed targets and ranges for measures that will be
used to assess performance at the end of the three-year performance
period and will be disclosed retrospectively.

Relative performance ranking

BP’s ranking place versus oil majors
First

Second

Third

Fourth or ﬁfth

Vesting percentage for each
relative performance measure
100%

80%

25%

Nil

Pension

Recognizes competitive practice in home country.

Policy summary

Operation and opportunity

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(cid:116)(cid:1)(cid:1)(cid:0)(cid:1)(cid:36)(cid:86)(cid:83)(cid:83)(cid:70)(cid:79)(cid:85)(cid:1)(cid:54)(cid:44)(cid:1)(cid:70)(cid:89)(cid:70)(cid:68)(cid:86)(cid:85)(cid:74)(cid:87)(cid:70)(cid:1)(cid:69)(cid:74)(cid:83)(cid:70)(cid:68)(cid:85)(cid:80)(cid:83)(cid:84)(cid:1)(cid:83)(cid:70)(cid:78)(cid:66)(cid:74)(cid:79)(cid:1)(cid:80)(cid:79)(cid:1)(cid:66)(cid:1)(cid:69)(cid:70)(cid:109)(cid:79)(cid:70)(cid:69)(cid:1)(cid:67)(cid:70)(cid:79)(cid:70)(cid:109)(cid:85)(cid:1)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.

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that apply to executives with an accrual rate of 1.3% of ﬁnal earnings (salary plus bonus) for each year of service.

Performance framework

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(cid:116)(cid:1)(cid:1)(cid:0)(cid:1)(cid:49)(cid:70)(cid:79)(cid:84)(cid:74)(cid:80)(cid:79)(cid:1)(cid:74)(cid:79)(cid:1)(cid:85)(cid:73)(cid:70)(cid:1)(cid:54)(cid:52)(cid:1)(cid:74)(cid:79)(cid:68)(cid:77)(cid:86)(cid:69)(cid:70)(cid:84)(cid:1)(cid:67)(cid:80)(cid:79)(cid:86)(cid:84)(cid:1)(cid:74)(cid:79)(cid:1)(cid:69)(cid:70)(cid:85)(cid:70)(cid:83)(cid:78)(cid:74)(cid:79)(cid:74)(cid:79)(cid:72)(cid:1)(cid:67)(cid:70)(cid:79)(cid:70)(cid:109)(cid:85)(cid:1)(cid:77)(cid:70)(cid:87)(cid:70)(cid:77)(cid:15)(cid:1)

Framework
Executive directors are eligible to participate in group pension schemes
that apply in their home countries which follow national norms in terms of
structure and levels.

US pension
Bob Dudley participates in the US plans. 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 formulas 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 (1) 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 (2) 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.

UK pension
Iain Conn and Dr Brian Gilvary participate in a UK ﬁnal salary pension
scheme in respect of service prior to 1 April 2011. This scheme provides a
pension relating to length of pensionable service and ﬁnal pensionable
salary. 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 2014 received cash
supplements of 35% of salary in lieu of future service accrual.

In the event of retirement before age 60, the following early retirement
terms would apply:

(cid:116) On retirement between 55 and 60, in circumstances approved by the

committee, an immediate unreduced pension in respect of the proportion
of their beneﬁt for service up to 30 November 2006, and subject to such
reduction as the scheme actuary certiﬁes in respect of the period of
service after 1 December 2006. The scheme actuary has, to date,
applied a reduction of 3% per annum for each year retirement precedes
60 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.

(cid:116) On leaving before age 55, in circumstances approved by the

committee, a deferred pension payable from 55 or later, with early
retirement terms if it is paid before 60 as set out above.

Irrespective of this, on leaving in circumstances of total incapacity, an
immediate unreduced pension is payable from their leaving date.

On leaving BP, Iain Conn is entitled to a deferred pension payable from age
55 or later. The early retirement terms applying to this pension are as set
out above.

2014 outcomes
In 2014, Mr Dudley’s accrued pension increased, net of inﬂation, by
$130,000; Dr Gilvary’s by £1,100 and Mr Conn’s by £900. These increases
have been reﬂected in the single ﬁgure table on page 75 by multiplying
them by twenty in accordance with the requirements of the UK regulations.
Dr Gilvary and Mr Conn participate in the UK pension arrangements
described above. Both individuals have exceeded the annual or lifetime
allowance under UK pensions legislation and, in accordance with the policy,
receive a cash supplement of 35% of salary. These cash supplements have
been separately identiﬁed in the single ﬁgure table on page 75.

Mr Dudley participates in the transitional arrangements in the US plans
described above. These are aimed at an accrual rate of 1.3% of ﬁnal
earnings (which include salary and bonus), for each year of service.

The committee continues to keep under review the increase in the value of
pension beneﬁts for individual directors. There are signiﬁcant differences in
calculation of pensions between the UK and the US. US pension beneﬁts
are not subject to cost of living adjustments after retirement as they are in
the UK. Equally, transfer values are frequently inﬂuenced by changes in
interest rates and discount factors.

The committee will continue to make the required disclosures in
accordance with the UK regulations; however, given the issues and
differences set out above, the committee would note that 12 to 14 would
be a typical annuity factor in the US compared with the factor of 20 upon
which the UK regulations are based.

BP Annual Report and Form 20-F 2014

Certain aspects of the arrangements described involved the exercise of
discretion by the committee in his favour. The committee was satisﬁed
that this was appropriate in view of his long and successful career with BP.

lain Conn was potentially entitled to a termination payment of up to
£453,677, calculated as approximately seven months of his base salary of
£797,000 per annum. This was to be paid in seven monthly instalments
from January 2015, but would cease to be payable in the event that he
commenced another employment prior to 24 July 2015. lain Conn
commenced employment with Centrica plc on 1 January 2015 and,
accordingly, no termination payment was made to him.

lain Conn worked for the full 2014 ﬁnancial year, and so was eligible for an
annual bonus payment paid in cash. The amount of this bonus is stated on
page 77.

lain Conn is entitled to an early retirement pension from age 55. In respect
of service from 1 December 2006 to his leaving date, he will be subject to
a 3% per annum reduction in his pension from age 55.

The share awards held by Iain Conn under the EDIP have been preserved
in accordance with the good leaver provisions and will vest at the normal
date, to the extent that performance targets are met:

(cid:116) Performance share awards granted in 2012, 2013 and 2014 (all of which

will be pro-rated to reﬂect Iain Conn’s period of service within the
performance cycle); and

(cid:116) Compulsory deferred bonus awards granted in 2012, 2013 and 2014,
voluntary deferred bonus awards granted in 2012 and 2013 and
matching share awards granted in 2012, 2013 and 2014. The vesting of
the matching share awards (but not the compulsory deferred bonus or
the voluntary deferred bonus) will be subject to time pro-rating.

Information on these preserved share awards (including the vesting of
share awards in the period up to 23 February 2015 and details of additional
shares awarded representing re-invested dividends on such vested
awards) is shown (pro-rated as appropriate) on pages 84 and 85.
The information relating to the vesting of share awards will be updated in
the 2015 and 2016 remuneration reports.

To the extent that matching share awards granted in 2014 and any
performance share awards vest, the post-tax number of shares will be
subject to a twelve-month retention period. Vested performance share
awards that are currently within their three-year post-vesting retention
period must be retained until 31 December 2015.

Iain Conn will continue to be covered by the company’s D&O insurance
and his indemnity in respect of third-party liabilities will continue in force
according to its terms. The company made a contribution towards his legal
fees in connection with these arrangements.

Historical data and statistics
Historical TSR performance

FTSE 100

£200

£150

£100

£50

g
n
d
o
h

0
0
1
£

a
c
i
t
e
h
t
o
p
y
h

f
o

e
u
a
V

2008

2009

2010

2011

2012

2013

2014

This graph shows the growth in value of a hypothetical £100 holding in BP
p.l.c. ordinary shares over six years, relative to a hypothetical £100 holding
in the FTSE 100 Index of which the company is a constituent. The values
of the hypothetical £100 holdings at the end of the six-year period were
£107.45 and £194.77 respectively.

Shareholder engagement
The committee values its dialogue with major shareholders on
remuneration matters. During the year, the committee’s chairman, the
committee’s independent adviser and the company secretary held
individual meetings with shareholders to ascertain their views and discuss
important aspects of the committee’s policy and its implementation. They
also met key proxy advisers. These meetings supplemented a group
meeting of major shareholders with all committee chairs and the chairman
which took place in March 2014, as well as an investor relations
programme including a regular ongoing dialogue between the chairman
and shareholders. Throughout the year this engagement provided the
committee with an important and direct perspective of shareholder views
and, together with the voting results on remuneration matters at the AGM,
was considered when making decisions.

Shareholders who voted against the report or withheld their vote did so for
several reasons. These related principally to insufﬁcient detailed
information to explain vesting outcomes and no ﬁrm commitment to
retrospective disclosure of targets currently deemed to be commercially
sensitive. For some, quantum was also an issue.

In his engagement, the chairman of the committee has sought to address
these issues. While the absolute quantum of remuneration is a product of
the implementation of the approved policy and of the performance of the
group, additional disclosure is now part of this report. Speciﬁcally, the
committee now discloses targets retrospectively for both annual bonus
and long-term performance shares unless there are speciﬁc conﬁdentiality
issues.

The board’s annual report on remuneration was approved by shareholders
at the 2014 AGM. The votes on the report are shown below.

2014 AGM directors’ remuneration report vote results
% vote ‘against’
Year
2014

% vote ‘for’
83.9%

Votes withheld
16.1% 2,218,417,773

The committee’s remuneration policy was approved by shareholders at the
2014 AGM. The votes on the policy are shown below.

2014 AGM directors’ remuneration policy vote results
Year
% vote ‘against’
2014

% vote ‘for’
96.4%

Votes withheld
3.6% 125,217,443

The shareholder approved policy now governs the remuneration of the
directors for a period of three years expiring in 2017. It is the board’s
intention that the policy be renewed at the AGM in 2017.
See bp.com/remuneration for a copy of the approved policy.

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 2014 are shown below.

Director
Bob Dudley

Iain Conn

Appointee company
Rosnefta
BT Group plcb

Rolls-Royce plcc

Additional position held at
appointee company
Director
Non-executive
director
Senior independent
director and chairman
of the ethics
committee

Total fees
0
£54,000

£29,300

a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft.
b Appointed 1 June 2014.
c Resigned 23 May 2014.

Executive director leaving the board
Iain Conn resigned as a director of the company and left BP’s employment
on 31 December 2014. This decision was announced on 24 July 2014, and
he served BP on his existing contractual terms until 31 December 2014
while working ﬁve months of the 12 months’ notice period speciﬁed in his
service contract. His settlement agreement dated 24 July 2014 is in
accordance with the policy and details are set out in the summary below.

BP Annual Report and Form 20-F 2014

History of CEO remuneration

Year
2009

2010c

2011

2012

2013

2014

CEO
Hayward

Hayward

Dudley

Total
remuneration
thousanda
£6,753

£3,890

$7,722

$8,312

$9,184
$14,620d
$15,334

Annual bonus
% of
maximum
89b
0

Performance
share vesting
% of maximum
17.5

16.7

45.5

60.5

a Total remuneration ﬁgures include pension and are shown as reported each year in the respective
Directors’ remuneration report with the exception of 2012 and 2013 which are restated in line
with the ﬁgures reported in the single ﬁgure tables in this report and in 2013.
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 Tony Hayward and Bob Dudley, although
Bob Dudley did not become CEO until October 2010.
d This number is detailed in the single ﬁgure table on page 75 and includes the actual outcomes of
the 2011-2013 performance share vesting.

Relative importance of spend on pay (million)

Distributions to
shareholders

Remuneration paid to
all employeesa

Capital investmentb

$22,892

$24,600

$13,936

$13,654

$11,938

Buybacksc
$4,770

$12,374

Buybacksc
$5,463

Dividendsd
$7,168

Dividendsd
$6,911

2014

2013

2014

2013

2014

2013

Total 3.5% decrease

2.1% increase

6.9% decrease

Dividends 3.7%
increase

Buybacks 12.7%
decrease

a Total remuneration reﬂects overall employee costs. See Financial statements – Note 33 for
further information.
b Capital investment reﬂects organic capital expenditure★. See footnote a on page 208 for further
information.
c See Financial statements – Note 29 for further information.
d Dividends includes both scrip dividends as well as those paid in cash. See Financial statements
– Note 8 for further information.

Percentage change in CEO remuneration

Comparing 2014 to 2013
% change in CEO remuneration

% change in comparator group
remuneration

Salary
Beneﬁts
Bonus
2.9% 26.7% -14.2%

3.4%a

0.0%b

-7.7%

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. This is the average across the comparator group.
b There was no change in employee beneﬁts structure. Those beneﬁts that are linked to salary
have changed in line with base salary increases.

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

C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
n
c
e

ﬂuctuations. The table below shows the status of each of the executive
directors in developing this level. These ﬁgures include the value as at
23 February 2015 from the directors’ interests shown below plus the
assumed vesting of the 2012-2014 performance shares and is consistent
with the ﬁgures reported in the single ﬁgure table on page 75.

Bob Dudley

Dr Brian Gilvary

Appointment date
October 2010

Value of current
shareholding
$10,147,581

January 2012

£3,618,299

% of policy
achieved
109

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 have sold shares that vested from the EDIP.

The ﬁgures below indicate and include all 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 as at the applicable dates.

Ordinary
shares or
equivalents at
1 Jan 2014
355,707
412,973

Ordinary
shares or
equivalents at
31 Dec 2014
738,858
545,217

Change from
31 Dec 2014
to
23 Feb 2015

Ordinary
shares or
equivalents
total at
23 Feb 2015
267,582 1,006,440
590,145
44,928

600,272

826,602

–

Current directors
Bob Dudleya
Dr Brian Gilvary
Former executive director
Iain Connb

a Held as ADSs.
b Includes 48,024 ordinary shares held as ADSs.

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.

Current directors
Bob Dudleya
Dr Brian Gilvary
Former executive director
Iain Conn

a Held as ADSs.

Performance
shares at
1 Jan 2014

Performance
shares at
31 Dec 2014
4,953,654 5,227,500
1,599,607 2,375,957

Performance
Change from
shares total at
31 Dec 2014 to
23 Feb 2015
23 Feb 2015
1,653,162 6,880,662
1,038,398 3,414,355

2,666,314 2,069,321

–

At 23 February 2015, 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 85.

Current director
Dr Brian Gilvary
Former executive director
Iain Conn

Options
504,191

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 other members of senior management who own
more than 1% of the ordinary shares in issue. At 23 February 2015, all
directors and other members of senior management as a group held
interests of 12,980,342 ordinary shares or their calculated equivalent,
10,295,017 performance shares or their calculated equivalent and
6,051,908 options over ordinary shares or their calculated equivalent under
the BP group share option schemes. Senior management comprises
members of the executive team. See pages 56-57 for further information.

★ Deﬁned on page 252.

BP Annual Report and Form 20-F 2014

Deferred shares (audited)a

Bonus year

Type

Performance
period

Date of award of
deferred shares

At 1 Jan
2014

Awarded
2014

At 31 Dec
2014

Awarded
2015

Potential maximum deferred shares

Number of
ordinary
shares
vested

£
Face value
of the award

Vesting date

Deferred share element interests

Interests vested in 2014 and 2015

Bob Dudleyb

2011

Dr Brian Gilvary

2012d

2013e

2014e

2010
2011
2012d

2013e

2014e

Former executive directors
Iain Conn

2010

2011

2012d

2013e

Dr Byron Groteb

2010

2011

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
2015-2017
Comp
2015-2017
Vol
Mat
2015-2017
DABf 2011-2013
DABf 2012-2014
2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
2015-2017
2015-2017
2015-2017

Comp
Vol
Mat
Comp
Mat
Comp
Vol
Mat

Comp
Mat
Comp
Vol
Mat
Comp
Vol
Mat
Comp
Mat
Comp
Vol
Mat
Comp
Vol
Mat
Comp
Vol
Mat

2011-2013
2011-2013
2012-2014
2012-2014
2012-2014
2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
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
11 Feb 2015
11 Feb 2015
11 Feb 2015
14 Mar 2011
15 Mar 2012
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
11 Feb 2015
11 Feb 2015
11 Feb 2015

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
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

–
–
–
–
–
–
– 149,628
– 149,628
–
–
–
–
–
–
–
44,971
–
73,624
–
78,815
–
78,815
157,630
–
96,653
–
96,653
–
–
–
–
–
–
–

21,384
21,384
80,652
80,652
161,304
80,648
80,648
161,296

26,604
26,604
44,340g
91,638
91,638
91,638g
97,278
97,278
32,424g

–
–
–
–
–
–
–
–
– 100,563
– 100,563
–
–
–
–
–
–
–
–
–

109,206
109,206
218,412
114,690
114,690
229,380
149,628
149,628
–
–
–
–
73,624
78,815
78,815
157,630
96,653
96,653
–
–
–

–
–
80,652
80,652
161,304
80,648
80,648
107,531g
100,563
33,521g
–
–
–
91,638
91,638
91,638g
97,278
97,278
32,424g

–
–
–
–
–
–
–
–
147,054
147,054
294,108
–
–
–
–
–
–
–
88,288
88,288
176,576

–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–
–

–
–
–
–
–
–
–
–

126,444c 11 Feb 2015
–
126,444c 11 Feb 2015
–
252,894c 11 Feb 2015
–
521,840
–
–
521,840
– 1,043,679
728,688
–
728,688
–
655,861
–
–
655,861
– 1,311,722
–
–
358,608
358,608
717,217
470,700
470,700
393,764
393,764
787,529

51,118c 9 Jan 2014
84,491c 15 Jan 2015
–
–
–
–
–
–
–
–

–
–
–
–
–
–
–
–

–
–
–
–
–

24,670c 12 Feb 2014
24,670c 12 Feb 2014
95,196c 11 Feb 2015
95,196c 11 Feb 2015
190,393c 11 Feb 2015
–
–
–
–
–
30,174c 12 Feb 2014
30,174c 12 Feb 2014
50,292c 12 Feb 2014
106,104c 11 Feb 2015
106,104c 11 Feb 2015
106,104c 11 Feb 2015
–
–
–

–
–
–

–
–
–
–
–
366,948
366,948
489,266
489,742
163,247
–
–
–
–
–
–
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 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 used to determine the total value at vesting on the vesting dates of 9 January 2014, 12 February 2014, 15 January 2015 and 11 February 2015 were £4.97, £4.87,
£3.93 and £4.46 respectively and for ADSs on 12 February 2014 and 11 February 2015 were $48.38 and $40.35 respectively.
d The face value has been calculated using the market price of ordinary shares on 11 February 2013 of £4.55.
e The market price at closing of ordinary shares on 12 February 2014 was £4.87 and for ADSs was $48.38 and on 11 February 2015 was £4.46 and for ADSs was $40.35. The sterling value has been
used to calculate the face value.
f 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.
g All matching shares have been pro-rated to reﬂect actual service during the performance period and these ﬁgures have been used to calculate the face value.

BP Annual Report and Form 20-F 2014

Performance shares (audited)

Share element interests

Interests vested in 2014 and 2015

Bob Dudleyb

Dr Brian Gilvary

Performance
period
2011-2013
2012-2014
2013-2015e
2014-2016e
2015-2017e
2011-2013f
2011-2013g
2012-2014
2013-2015e
2014-2016e
2015-2017e

Date of award of
performance shares
09 Mar 2011
08 Mar 2012
11 Feb 2013
12 Feb 2014
11 Feb 2015
14 Mar 2011
14 Mar 2011
08 Mar 2012
11 Feb 2013
12 Feb 2014
11 Feb 2015

Former executive directors
Iain Conn

2011-2013
2012-2014
2013-2015e
2014-2016e
2011-2013
2012-2014
2013-2015e

09 Mar 2011
08 Mar 2012
11 Feb 2013
12 Feb 2014
09 Mar 2011
08 Mar 2012
11 Feb 2013

Dr Byron Groteb

Potential maximum performance sharesa

At 1 Jan
2014
1,330,332
1,343,712
1,384,026
–
–
67,500
22,500
624,434
637,413
–
–

623,025
660,633
694,688
–
654,498
414,468
142,278

Awarded
2014
–
–
–
1,304,922
–
–
–
–
–
605,544
–

–
–
–
660,128
–
–
–

At 31 Dec
2014
–
1,343,712
1,384,026
1,304,922
–
–
–
624,434
637,413
605,544
–

–
660,633
463,126h
220,043h
–
414,468h
142,278h

Awarded
2015
–
–
–
–
1,501,770
–
–
–
–
–
685,246

–
–
–
–
–
–
–

Number of
ordinary
shares
vested

–
–
–

Vesting date
702,582c15 May 2014d
941,286c March 2015
–
–
–
76,726c 9 Jan 2014
25,824c 6 Feb 2014
445,912c March 2015
–
–
–

–
–
–

–
–

335,452c15 May 2014d
471,761c March 2015
–
–
345,654c15 May 2014d
290,346c March 2015
–

–

£
Face value
of the award
–
–
6,297,318
6,354,970
6,697,894
–
–
–
2,900,229
2,948,999
3,056,197

–
–
2,107,223
1,071,609
–
–
647,365

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a 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.
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 9 January 2014 was £4.97, at 6 February 2014 was £4.77 and 15 May 2014 was £5.03 and for ADSs was $50.90. For the assumed vestings
dated March 2015 a price of £4.27 per ordinary share and $40.74 per ADS has been used. These are the average prices from the fourth quarter of 2014.
d The 2011-2013 award vested on 15 May 2014 with an additional vesting of accrued notional dividends on 24 June 2014 on which the market price of each share was £5.24 and for ADSs was $52.84.
For Byron Grote this resulted in an increase in value at vesting of $708,913 and for Bob Dudley and lain Conn details can be found in the single ﬁgure table on page 75.
e The market price at closing of ordinary shares on 11 February 2013 was £4.55 and for ADSs was $43.01, on 12 February 2014 was £4.87 and for ADSs was $48.38, and on 11 February 2015 was
£4.46 and for ADSs was $40.35.
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 has been pro-rated to reﬂect actual service during the performance period and these ﬁgures have been used to calculate the face value.

Share interests in share option plans (audited)

Dr Brian Gilvary

Option type
BP 2011
SAYE

At 1 Jan 2014
500,000
4,191

Granted
–
–

Exercised At 31 Dec 2014
500,000
4,191

–
–

Option price
£3.72
£3.68

Market price at
date of exercise
–
–

Date from which
ﬁrst exercisable
07 Sep 2014
01 Sep 2016

Expiry date
07 Sep 2021
28 Feb 2017

Former executive directors
Iain Conn

SAYE
SAYE

–a
797
2,005b
3,017
The closing market prices of an ordinary share and of an ADS on 31 December 2014 were £4.11 and $38.12 respectively.
During 2014 the highest market prices were £5.27 and $53.48 respectively and the lowest market prices were £3.64 and $34.88 respectively.
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 The option lapsed on Iain Conn’s departure from the board in accordance with the rules.
b Potential maximum shares have been pro-rated with a shorter exercise period in accordance with the rules.

£3.16
£3.68

–
–

–
01 Jan 2015

31 Dec 2014
30 Jun 2015

BP Annual Report and Form 20-F 2014

Non-executive directors
This section of the directors’ remuneration report completes the directors’ annual report on remuneration with details for the chairman and non-executive
directors (NEDs). The board’s remuneration policy for the NEDs was approved at the 2014 AGM. This policy was implemented during 2014. There has
been no variance of the fees or allowances for the chairman and the NEDs during 2014.

Chairman

Basic fee

(cid:116)(cid:1) 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.

Operation and opportunity

(cid:116)(cid:1) The quantum and structure of chairman’s remuneration is reviewed annually by the remuneration committee, which makes a recommendation to the

board.

Beneﬁts and expenses

(cid:116)(cid:1) The chairman is provided with support and reasonable travelling expenses.

Operation and opportunity

(cid:116)(cid:1) 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.

Fee structure
The table below shows the fee structure for the chairman in place since
1 May 2013. He is not eligible 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.

Chairman

Fee level
£ thousand
785

The table below shows the fees paid for the chairman for the year ending
31 December 2014.

2014 remuneration (audited)
£ thousand

Carl-Henric Svanberg

Fees

2013
773

2014
785

Beneﬁtsa

2014
37

2013
49

2014
822

Total

2013
822

a Beneﬁts include travel and other expenses relating to the attendance at board and other
meetings. Amounts disclosed have been grossed up using a tax rate of 45%, where relevant, as
an estimation of tax due.

Chairman’s interests
The ﬁgures below include all the beneﬁcial and non-beneﬁcial interests of
the chairman in shares of BP (or calculated equivalents) that have been
disclosed under the DTRs as at the applicable dates. The chairman’s
holdings represented as a percentage against policy achieved are 610%.

Ordinary
shares or
equivalents at
1 Jan 2014

Ordinary
shares or
equivalents at
31 Dec 2014
1,039,276 1,076,695

Change from
31 Dec 2014
to
23 Feb 2015

Ordinary
shares or
equivalents
total at
23 Feb 2015
– 1,076,695

Chairman
Carl-Henric Svanberg

BP Annual Report and Form 20-F 2014

Non-executive directors

Basic fee

(cid:116)(cid:1) 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.

Operation

(cid:116)(cid:1) 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.

(cid:116)(cid:1) Remuneration for non-executive directors is reviewed annually.

Committee fees and allowances

Intercontinental allowance
Intercontinental allowance
(cid:116)(cid:1) 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.

Operation

(cid:116)(cid:1) The allowance will be paid in cash following each event of intercontinental travel.

CCoommmmiitttteeee cchhaaiirrmmaansnshhiip p ffeeee
Committee chairmanship fee
(cid:116)(cid:1) 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.

CCoommmmiitttteee e mmeemmbeberrsshhiip p ffeeee
Committee membership fee
(cid:116)(cid:1) 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.

Operation

(cid:116)(cid:1) Fees for committee chairmanship and membership are determined annually and paid in cash.

TThhee sseeninioor r iinnddeeppeennddeenntt ddiirreeccttoorr ((SSIIDD))
The senior independent director (SID)
(cid:116)(cid:1) 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

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chair or member.

Operation

(cid:116)(cid:1) The fee for the SID will be determined from time to time, and is paid in cash monthly.

Beneﬁts and expenses

(cid:116)(cid:1) The NEDs are provided with support and reasonable travelling expenses.

Operation

(cid:116)(cid:1) NEDs are reimbursed for all reasonable travelling and subsistence expenses (including any relevant tax) incurred in carrying out their duties.

PPrrooffeessssiioonnaal l ffeeees s
Professional fees
(cid:116)(cid:1) Fees will be reimbursed in the form of cash, payable following assistance.

Operation

(cid:116)(cid:1) 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.

BP Annual Report and Form 20-F 2014

Fee structure
The table below shows the fee structure for non-executive directors from
1 May 2014:

2014 remuneration (audited)
£ thousand

Senior independent directora
Board member
Audit, Gulf of Mexico, remuneration and
SEEA committees chairmanship feesb
Committee membership feec
Intercontinental travel allowance

Fee level
£ thousand
120
90
30

20
5

a The senior independent director is eligible for committee chairmanship fees and intercontinental
travel allowance plus any committee membership fees.
b For members of the audit, Gulf of Mexico, SEEA and remuneration committees.
c Committee chairmen do not receive an additional membership fee for the committee they chair.

Paul Anderson
Alan Boeckmannb
Admiral Frank Bowman
Antony Burgmans
Cynthia Carroll
George Davidc
Ian Davis
Professor Dame Ann Dowlingd
Brendan Nelson
Phuthuma Nhleko
Andrew Shilston

Fees

Beneﬁtsa

Total

2014
175
70
165
150
125
185
150
140
125
150
150

2013
175
–
165
145
120
185
150
140
130
150
150

2014
48
17
17
9
66
18
5
11
16
9
8

2014
223
87
182
159
191
203
155
151
141
159
158

2013
175
–
165
145
120
185
150
140
130
150
150

a Beneﬁts include travel and other expenses relating to the attendance at board and other
meetings. Amounts disclosed are estimated and have been grossed up using a tax rate of 45%,
where relevant, as an estimation of tax due. These are disclosed for 2014 following approval of
the policy.
b Appointed on 24 July 2014.
c In addition, George David received £12,500 for chairing the BP technology advisory council until
1 July 2013.
d In addition, Professor Dame Ann 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.

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
Paul Anderson
Alan Boeckmannb
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.
b Appointed on 24 July 2014.

Ordinary shares
or equivalents at
1 Jan 2014
30,000a
–
16,320a
10,156
10,500a
579,000a
11,449
22,320
11,040
–
15,000

Ordinary shares
or equivalents at
31 Dec 2014
30,000a
43,890a
16,320a
10,156
10,500a
579,000a
22,420
22,320
11,040
–
15,000

Change from
31 Dec 2014 to
23 Feb 2015
–
–
–
–
–
–
–
–
–
–
–

Ordinary shares
or equivalents
total at
23 Feb 2015
30,000a
43,890a
16,320a
10,156
10,500a

Value of
current
shareholding
$206,100
$301,524
$112,118
£45,194
$72,135
579,000a $3,977,730
£99,769
£99,324
£49,128
–
£66,750

22,420
22,320
11,040
–
15,000

% of policy
achieved
139
203
76
50
49
2,684
111
110
55
0
56

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 2014, he received £100,000 for this role.

This directors’ remuneration report was approved by the board and signed on its behalf by David J Jackson, company secretary on 3 March 2015.

BP Annual Report and Form 20-F 2014

Financial
statements

90 Statement of directors’ responsibilities

91 Consolidated financial statements of the BP group

Independent auditor’s reports
Group income statement
Group statement of
comprehensive income

91
96

Group statement of changes in
equity
Group balance sheet
Group cash flow statement

100 Notes on financial statements

3.
4.
5.
6.
7.
8.
9.

10.

100

Significant accounting
policies
Significant event – Gulf of
Mexico oil spill
111
Disposals and impairment 117
Segmental analysis
119
Income statement analysis 123
Exploration expenditure
124
Taxation
124
Dividends
126
Earnings per ordinary
share
Property, plant and
equipment

126

11. Capital commitments
12. Goodwill
13.
14.

Intangible assets
Investments in joint
ventures
Investments in associates

15.
16. Other investments
Inventories
17.
Trade and other
18.
receivables

19. Valuation and qualifying

accounts
Trade and other payables

20.

128
128
129
130

131
131
134
134

134

135
135

21.
22.

Provisions
Pensions and other post-
retirement benefits

135
23. Cash and cash equivalents 142
24.
142
25. Capital disclosures and

Finance debt

analysis of changes in net
debt

26. Operating leases
27.

Financial instruments and
financial risk factors
28. Derivative financial
instruments

29. Called-up share capital
30. Capital and reserves
31. Contingent liabilities
32. Remuneration of senior
management and non-
executive directors
Employee costs and
numbers

33.

34. Auditor’s remuneration
35. Subsidiaries, joint
arrangements and
associates

36. Condensed consolidating
information on certain US
subsidiaries

167 Supplementary information on oil and natural gas

(unaudited)

Oil and natural gas exploration
and production activities
Movements in estimated net
proved reserves

168

174

Standardized measure of
discounted future net cash
flows and changes therein
relating to proved oil and gas
reserves
Operational and statistical
information

197 Parent company financial statements of BP p.l.c.

Company balance sheet
Company cash flow statement
Company statement of total
recognized gains and losses
Notes on financial statements
1. Accounting policies
2.
3.
4. Debtors

Taxation
Fixed assets – investments

197
198

198
199
199
200
200
201

Creditors
Pensions
Called-up share capital
Capital and reserves
Cash flow

5.
6.
7.
8.
9.
10. Contingent liabilities
11. Share-based payments
12. Auditor’s remuneration
13. Directors’ remuneration

97
98
99

135

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143
143

144

147
152
154
157

158

159
159

160

161

192

195

201
201
204
204
205
205
205
205
205

BP Annual Report and Form 20-F 2014

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 211 to 212 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 36 to 38 and elsewhere in this report, including Safety on pages 39 to 41. 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
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
3 March 2015

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 2014

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 financial statements
In our opinion:
• the financial statements give a true and fair view of the state of the group’s and of the parent company’s affairs as at 31 December 2014 and of the

group’s profit for the year then ended;

(cid:129) the group financial statements have been properly prepared in accordance with IFRS as adopted by the European Union;
(cid:129) the parent company financial statements have been properly prepared in accordance with United Kingdom Generally Accepted Accounting Practice;

and

(cid:129) the financial statements have been prepared in accordance with the requirements of the Companies Act 2006 and, as regards the group financial

statements, 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 on the group financial statements we have considered the adequacy of the disclosure in Note 2 to the financial statements
concerning the provisions, future expenditures which cannot be reliably estimated and other contingent liabilities related to the claims, penalties and
litigation arising from the Gulf of Mexico oil spill. The total amount that will ultimately be paid by BP in relation to all obligations arising from this
significant event is subject to significant uncertainty and the ultimate exposure and cost to BP is dependent on many factors, including but not limited
to, the determinations of the Courts and Regulatory authorities in the US. Significant uncertainty exists in relation to the amount of claims that will
become payable by BP and the amount of fines that will be levied on BP (including any ultimate determination of BP’s culpability based on negligence,
gross negligence or wilful misconduct). The outcome of litigation and the cost of the longer term environmental consequences of the oil spill are also
subject to significant uncertainty. For these reasons it is not possible to estimate reliably the ultimate cost to 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
We have audited the financial statements of BP p.l.c. for the year ended 31 December 2014 which comprise the Group income statement, the Group
statement of comprehensive income, the Group statement of changes in equity, the Group and Parent Company balance sheets, the Group and Parent
Company cash flow statements, the Parent Company statement of total recognized gains and losses and the related notes. The financial reporting
framework that has been applied in the preparation of the group financial statements is applicable law and International Financial Reporting Standards
(IFRS) as adopted by the European Union. The financial reporting framework that has been applied in the preparation of the parent company financial
statements 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 90, the directors are responsible for the preparation of the
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 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 group’s and 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 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:
(cid:129) the determination of the liabilities, contingent liabilities and disclosures arising from the significant uncertainties related to the Gulf of Mexico oil spill

(See AC and AP)*;

(cid:129) the significant decline in oil and gas prices since late 2014 has the potential for a material impact on the carrying value of the group’s assets. We

reconsidered our risk assessment at the year end to recognise this significant development (See AC and AP)*;

(cid:129) the estimate of oil and gas reserves and resources which has a significant impact on impairment tests, depreciation, depletion & amortisation and

decommissioning provisions (See AC and AP)*;

(cid:129) unauthorized trading activity within the Integrated Supply and Trading function and the potential impact on revenue (See AC)*;
(cid:129) BP’s ability to exercise significant influence over Rosneft and the consequent accounting for the interest in Rosneft using the equity method

(See AC and AP)*;

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The maintenance and integrity of the BP p.l.c website is the responsibility of BP p.l.c.; 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.
Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

2.
* These risks are discussed in other areas of this report as noted by the following key:
AC – see Audit Committee Report on pages 64 to 67.
AP – see Financial statements—Note 1 Significant accounting policies, judgements, estimates and assumptions on pages 100 to 110.

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 2014

With the exception of the risk related to the recent significant decrease in the oil price the other risks are consistent with the prior year. The risk we
identified in the prior year related to the determination of the fair value of the assets and liabilities of the Rosneft business on acquisition of the equity
interest is not relevant to the current period as the acquisition was completed and accounted for in the prior year.

Our application of materiality
We quantify materiality in planning and executing the audit and in evaluating the materiality of misstatements on the financial statements and the
effect they have on our audit. In determining if 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. The evaluation of materiality requires professional judgement and the consideration of
both qualitative and quantitative factors.

We determined materiality for the group to be $1 billion (2013 $1 billion), which represents 5% of underlying replacement cost profit (as defined on
page 255) before tax having added back charges related to the Gulf of Mexico oil spill response. We used this measure to calculate our materiality to
exclude the impact of both changes in crude oil and product prices and items disclosed as non-operating items that can significantly distort the results.
This provides a basis for assessing the importance of misstatements and in determining the scope of our audit procedures.

We determined, based on our risk assessment and consideration of the group’s control environment, that performance materiality be set at 75% of our
materiality for the group, namely at $750 million (2013 $750 million). Performance materiality is the application of materiality at an individual account or
balance level and is set to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements
exceeds materiality. Audit work on individual locations is undertaken using a percentage of our total performance materiality. We allocate performance
materiality to the components of the group we audit based on their relative risk and size. The range of performance materiality allocated to components
in 2014 was $150 million to $640 million (2013 $150 million to $640 million).

We agreed with the Audit Committee to report all audit differences in excess of $50 million (2013 $50 million).

We evaluate any uncorrected misstatements against both the quantitative measures of materiality discussed above and in the light of other relevant
qualitative considerations.

An overview of the scope of our audit
Our audit scope is risk based and is designed to focus our efforts on the areas at greatest risk of material misstatement, aspects subject to significant
management judgement and on the locations of greatest complexity, risk and size. We design and execute our audit based primarily on our
assessment of the risks particular to this company and the industry in which it operates.

In scoping the audit we view the group as 42 Regional Performance Units (‘RPUs’) plus the group functions. The group audit scope focused on 19
RPUs in the US, Azerbaijan, Angola, UK, Germany, Russia, Singapore and the group functions. We designed specific procedures for these locations
and functions to provide an appropriate basis for executing audit work to address the risk of material misstatement. This included the audit of all
accounts that were impacted by our assessment of the risks of material misstatement (identified above). We note that for these RPUs we do not
include all balances at these entities in our specific audit scope, based on our assessment of risk we exclude certain low risk, lower value balances.
The specific in scope locations represent audit coverage of 71% (2013 68%) of revenue and 63% (2013 72%) of property, plant and equipment. Our
procedures at the locations in group scope included assessment and testing of management’s financial controls and other substantive and analytical
verification procedures. For those locations and balances that are not subject to specific group scoping (there are many small, low risk locations and
balances in the 23 RPUs not included in our specific scope) we assess and test management’s group wide controls and undertake analytical and
enquiry procedures to address the residual risk of material misstatement.

One of the key locations is Russia which includes Rosneft, a material associate not controlled by BP. We were provided with appropriate access to
Rosneft’s auditors in order to ensure they had completed the procedures required by ISA 600 on the financial statements of Rosneft used as the basis
for BP’s equity accounting.

The Group audit team continued to undertake a programme of planned visits to significant locations to ensure the audit is executed and delivered in
accordance with the planned approach and to confirm the quality of the audit work undertaken.

Our response to the risks of material misstatement identified above included the following procedures:

The determination of the liabilities, contingent liabilities and disclosures arising from the significant uncertainties related to the Gulf of
Mexico oil spill
We continued to assess developments in legal cases related to claims and penalties through reading the determinations and judgments made by the
courts, discussions with the BP legal team and correspondence with external lawyers. The determination of liabilities related to the oil spill takes
months and years to evolve and during 2014 there were some significant developments in loss claims and potential penalties, specifically related to the
Economic and Property Damages Settlement Agreement and Clean Water Act penalties (see Note 2), that we considered in assessing the
requirements of IFRS in relation to liabilities, contingent liabilities and disclosure. Where appropriate we deployed valuation and modelling experts to
inform our assessment. There is significant uncertainty related to the ultimate liabilities and we considered the disclosures related to these
uncertainties and concluded that it was appropriate to include an emphasis of matter related to these uncertainties in this report.

The significant decline in oil and gas prices since late 2014 has the potential for a material impact on the carrying value of the group’s
assets.
Movements in commodity prices can have a significant effect on the carrying value of the group’s assets. A significant and rapid drop in prices will also
quickly impact the group’s operations and cash flows. We assessed the principal risk arising in relation to the financial statements to be associated
with the carrying value of tangible and intangible assets, many of which are supported by an assessment of future cash flows. The assessment of the
asset carrying values is further complicated as external market evidence, such as market transactions, become less reliable in a period of significant
change to the price of oil. We extended the scope of our procedures to address the change in risk profile of the group’s assets and to scrutinize
impairment considerations. We extended the use of our own valuation experts and external data in critically assessing and corroborating the revised
assumptions used in impairment testing, the most significant being future market oil prices, reserves and resources volumes and discount rates. We
also performed audit procedures on the mathematical integrity of the impairment models and sensitivity analysis and procedures to ensure the
completeness of the impairment charge and exploration write offs.

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 2014

The estimate of oil and gas reserves and resources which has a significant impact on impairment tests, depreciation, depletion &
amortisation and decommissioning provisions
We carried out testing of controls over BP’s internal certification process for technical and commercial experts who are responsible for reserves
estimation. We assessed whether the significant changes in proved reserves have been made in compliance with relevant regulations. We ensured
that the updated reserves and resources estimates were included appropriately in consideration of impairment, depreciation, depletion and
amortization and decommissioning provisions.

Unauthorized trading activity and the potential impact on revenue
We performed testing relating to controls over unauthorized trading activity. 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 obtained confirmations directly from third parties for a sample of
trades. We verified the fair value of a sample of derivatives using contract and external market prices. We tested the completeness of the amounts
recorded in the financial statements through performing procedures to detect unrecorded liabilities as well as detailed cut off procedures around sales,
purchases, trade receivables, and trade payables.

BP’s ability to exercise significant influence over Rosneft and the consequent accounting for the interest in Rosneft using the equity
method
We challenged the evidence available to support BP’s continuing conclusion that Rosneft should be accounted using the equity method. We assessed
the impact of sanctions imposed by the US and European Union through discussion with the BP legal team, consideration of EY internal guidance and
observation of the interaction between BP and Rosneft. We also considered the adequacy of the financial and other information provided to BP to
allow compliance with its reporting obligations. We ensured appropriate review was completed by BP on the information reported. We provided
instruction to Rosneft’s auditors who reported in accordance with our timetable and instructions.

Opinion on other matter 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 financial statements.

Matters on which we are required to report by exception
We have nothing to report in respect of the following:
Under the ISAs (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;

• 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.
Under the Companies Act 2006 we are required 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.

Under the Listing Rules we are required to review:
• the directors’ statement, set out on page 90, 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

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Governance Code specified for our review.

John C. Flaherty (Senior Statutory Auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
3 March 2015

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 2014

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 2014, 31 December 2013 and 1 January 2013, 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 2014. 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
2014, 31 December 2013 and 1 January 2013, and the group results of its operations and its cash flows for each of the three years in the period ended
31 December 2014, 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 on the group financial statements we have considered the adequacy of the disclosure in Note 2 to the financial statements
concerning the provisions, future expenditures which cannot be reliably estimated and other contingent liabilities related to the claims, penalties and
litigation arising from the Gulf of Mexico oil spill. The total amount that will ultimately be paid by BP in relation to all obligations arising from this
significant event is subject to significant uncertainty and the ultimate exposure and cost to BP is dependent on many factors, including but not limited
to, the determinations of the Courts and Regulatory authorities in the US. Significant uncertainty exists in relation to the amount of claims that will
become payable by BP and the amount of fines that will be levied on BP (including any ultimate determination of BP’s culpability based on negligence,
gross negligence or wilful misconduct). The outcome of litigation and the cost of the longer term environmental consequences of the oil spill are also
subject to significant uncertainty. For these reasons it is not possible to estimate reliably the ultimate cost to BP. Our opinion is not qualified in respect
of these matters.

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 2014, 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 3 March 2015 expressed
an unqualified opinion.

/s/ Ernst & Young LLP
London, England
3 March 2015

The maintenance and integrity of the BP p.l.c. website are the responsibility of BP p.l.c.; 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.
Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

BP Annual Report and Form 20-F 2014

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 2014, 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 240. 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 2014, 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 2014 and 2013, 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 2014, and our report dated 3 March
2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP
London, United Kingdom
3 March 2015

Consent of independent registered public accounting firm

We consent to the incorporation by reference of our reports dated 3 March 2015, 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
2014 in the following Registration Statements:

Registration Statement on Form F-3 (File No. 333-201894-01) of BP Capital Markets p.l.c. and BP p.l.c.; and
Registration Statements on Form S-8 (File Nos.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, 333-186462, 333-199015, 333-200794, 333-200795 and
333-200796) of BP p.l.c.

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London, England
3 March 2015

BP Annual Report and Form 20-F 2014

Note

2014

2013

353,568
570
2,802
843
895

358,678
281,907
27,375
2,958
15,163
8,965
3,632
12,696
(430)

6,412
1,148
314

4,950
947

4,003

3,780
223

4,003

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

2012

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

20.55
20.42

123.87
123.12

57.89
57.50

4
14
15
5
3

4
4
3
6

5
22

30
30

9
9

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 expensesa
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 costsa
Net finance expense relating to pensions and other post-retirement benefits

Profit before taxation
Taxationa

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

a See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.

BP Annual Report and Form 20-F 2014

Group statement of comprehensive incomea
For the year ended 31 December

Profit for the year
Other comprehensive income
Items that may be reclassified subsequently to profit or loss

Note

2014
4,003

2013
23,758

$ million

2012
11,251

Currency translation differences
Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on sale of

(6,838)

(1,608)

485

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

28
28
28

51
(1)
1
(155)
(73)
(11)
(2,584)
147
(9,463)

(4,590)
4
1,334
(3,252)

(12,715)

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

(8,712)

22,866

12,226

(8,903)
191
(8,712)

22,574
292
22,866

11,988
238
12,226

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Other comprehensive income

Total comprehensive income

Attributable to

BP shareholders
Non-controlling interests

a See Note 30 for further information.
Group statement of changes in equitya

At 1 January 2014
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 2014

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

a See Note 30 for further information.

Share
capital
and
capital
Treasury
reserves
shares
43,656 (20,971)
–
–
–
–
–
252
–
–
43,902 (20,719)

–
–
–
–
–
246
–
–

Foreign
currency
translation
reserve
3,525
–
(6,934)
(6,934)
–
–
–
–
–
(3,409)

Fair
value
reserves

Profit
and loss
account
(695) 103,787
3,780
(5,547)
(1,767)
(5,850)
(3,366)
(313)
73
–
(897) 92,564

–
(202)
(202)
–
–
–
–
–

43,513 (21,054)
–
–
–
–
–
83
–
–
43,656 (20,971)

–
–
–
–
–
143
–
–

43,454 (21,323)
–
–
–
–
269
–
43,513 (21,054)

–
–
–
–
59
–

5,128
–
(1,603)
(1,603)
–
–
–
–
–
3,525

89,184
1,775
23,451
–
(2,470)
3,196
(2,470) 26,647
(5,441)
(6,923)
247
73
–
(695) 103,787

–
–
–
–
–

4,509
–
619
619
–
–
–
5,128

267
–
1,508
1,508
–
–
–
1,775

84,661
11,017
(1,156)
9,861
(5,294)
(44)
–
89,184

BP
shareholders’
equity
129,302
3,780
(12,683)
(8,903)
(5,850)
(3,366)
185
73
–
111,441

Non-
controlling
interests
1,105
223
(32)
191
(255)
–
–
–
160
1,201

118,546
23,451
(877)
22,574
(5,441)
(6,923)
473
73
–
129,302

111,568
11,017
971
11,988
(5,294)
284
–
118,546

1,206
307
(15)
292
(469)
–
–
–
76
1,105

1,017
234
4
238
(82)
–
33
1,206

$ million

Total
equity
130,407
4,003
(12,715)
(8,712)
(6,105)
(3,366)
185
73
160
112,642

119,752
23,758
(892)
22,866
(5,910)
(6,923)
473
73
76
130,407

112,585
11,251
975
12,226
(5,376)
284
33
119,752

BP Annual Report and Form 20-F 2014

Group balance sheet
At 31 December

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

Total assets

Current liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions

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

C-H Svanberg Chairman
R W Dudley Group Chief Executive
3 March 2015

BP Annual Report and Form 20-F 2014

Note

2014

10
12
13
14
15
16

18
28

7
22

17
18
28

16
23

20
28

24
7
21
22

$ million

2013

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

130,692
11,868
20,907
8,753
10,403
1,228

183,851
659
4,787
4,442
964
2,309
31

197,043

333
18,373
31,038
5,165
1,424
837
329
29,763

87,262

284,305

305,690

40,118
3,689
7,102
6,877
2,011
3,818

63,615

3,587
3,199
861
45,977
13,893
29,080
11,451

47,159
2,322
8,960
7,381
1,945
5,045

72,812

4,756
2,225
547
40,811
17,439
26,915
9,778

108,048

102,471

171,663

175,283

112,642

130,407

30
30

111,441
1,201

112,642

129,302
1,105

130,407

Group cash flow statement
For the year ended 31 December

Operating activities

Profit before taxation

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 disposed
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 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

Note

2014

2013

$ million

2012

4,950

30,221

18,131

6
4
3

3
3

3,029
15,163
8,070
(3,372)
1,911
(276)
81
1,148
(937)
314
379

(963)
1,119
10,169
3,566
(6,810)
(4,787)

32,754

(22,546)
(131)
(179)
(336)
1,820
1,671
127

(19,574)

(4,589)
12,394
(6,282)
(693)
9

(5,850)
(255)

(5,266)

(671)

7,243
22,520

29,763

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)

21,100

20,479

(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)

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)

5,458
14,177

19,635

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BP Annual Report and Form 20-F 2014

Notes on financial statements

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 2014 were approved and signed by the group chief executive
and chairman on 3 March 2015 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
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 2014. The accounting policies that follow have been consistently applied to all years presented.

The consolidated financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where
otherwise indicated.

Significant 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 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: accounting for 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. 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. Intra-group balances and transactions, including unrealized profits arising from intra-group 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 BP shareholders.

Interests in other entities
Business combinations and goodwill
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. 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 arising on business combinations prior to 1 January 2003 is stated at the previous carrying amount under UK generally accepted accounting
practice, less subsequent impairments.

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.

Interests in joint arrangements
The results, assets and liabilities of joint ventures 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. 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
The results, assets and liabilities of associates are incorporated in these financial statements using the equity method of accounting as described below.

Significant estimate or judgement: accounting for interests in other entities
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.

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1. Significant accounting policies, judgements, estimates and assumptions – continued

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.

Since 21 March 2013, BP has 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
2014. 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
and he is a member of the Rosneft board’s Strategic Planning Committee. 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.

The equity method of accounting
Under the equity method, the investment is carried on the balance sheet at cost plus post-acquisition changes in the group’s share of net assets of the
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 of disposal and value in use. If 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 from the date on 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.

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 inventories sold in the
period and is arrived at by excluding inventory holding gains and losses from profit. Replacement cost profit for the group is not a recognized measure
under IFRS. For further information see Note 4.

Foreign currency translation
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of those
entities 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, unless hedge accounting is applied. 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. In the consolidated
financial statements, 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 intra-group 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 related cumulative exchange gains and losses recognized in equity are 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 or amortized once classified as held for sale.

BP Annual Report and Form 20-F 2014

101

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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 trade marks and are stated at the amount initially recognized, less accumulated amortization and accumulated impairment losses.

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 trade marks, 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.

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: oil and natural gas accounting
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. an 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 or 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.

One of the facts and circumstances which indicate that an entity should test such assets for impairment is that the period for which the entity has a
right to explore in the specific area has expired or will expire in the near future, and is not expected to be renewed.

BP has leases in the Gulf of Mexico making up a prospect, some with terms which were scheduled to expire at the end of 2013 and some with
terms which were scheduled to expire at the end of 2014. A significant proportion of our capitalized exploration and appraisal costs in the Gulf of
Mexico relate to this prospect. This prospect requires the development of subsea technology to ensure that the hydrocarbons can be extracted
safely. BP is in negotiation with the US Bureau of Safety and Environmental Enforcement in relation to seeking extension of these leases so that the
discovered hydrocarbons can be developed. BP remains committed to developing this prospect and expects that the leases will be renewed and,
therefore, continues to carry the capitalized costs on its balance sheet.

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, finance 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.

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

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1. Significant accounting policies, judgements, estimates and assumptions – continued

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.

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.

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: estimation of oil and natural gas reserves
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 167, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes are provided on
page 219.

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 2014 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 167. 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 4
respectively.

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Impairment of property, plant and equipment, intangible assets, and goodwill
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 or decommissioning costs. 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 of disposal 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.

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 market
assumptions, such as oil prices, natural gas prices, refining margins, refined product margins and cost inflation rates, are set by senior management.
These market assumptions take account of existing prices, global supply-demand equilibrium for oil and natural gas, other macroeconomic factors and
historical trends and variability. 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 of disposal is 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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1. Significant accounting policies, judgements, estimates and assumptions – continued

Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the group of
cash-generating units to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the
group of CGUs (including goodwill) is compared with their recoverable amount. The recoverable amount of a group of CGUs to which goodwill is
allocated is the higher of value in use and fair value less costs of disposal. Where the recoverable amount of the group of CGUs to which goodwill has
been allocated is less than the carrying amount, an impairment loss is recognized. An impairment loss recognized for goodwill is not reversed in a
subsequent period.

Significant estimate or judgement: recoverability of asset carrying values
Determination as to whether, and by how much, an asset or group of CGUs containing goodwill 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.

The estimated future level of production in all impairment tests is based on assumptions about future commodity prices, production and
development costs, field decline rates, current fiscal regimes and other factors.

Fair value less costs of disposal may be determined based on similar recent market transaction data or, where recent market transactions for the
asset are not available for reference, using discounted cash flow techniques. Where discounted cash flow analyses are used to calculate fair value
less costs of disposal, accounting judgements are made about the assumptions market participants would use when pricing an asset, a CGU or a
group of CGUs containing goodwill and the test is performed on a post-tax basis. The discount rate used is the group’s post-tax weighted average
cost of capital (2014 8%), with a 2% premium added in higher-risk countries. Reserves assumptions for fair value less costs of disposal discounted
cash flow tests consider all reserves that a market participant would consider when valuing the asset, which are usually broader in scope than the
reserves used in a value-in-use test. Discounted cash flow analyses used to calculate fair value less costs of disposal use market prices for the first
five years and long-term price assumptions that are consistent with the assumptions used by the group for investment appraisal purposes
thereafter. The long-term oil price assumption used in such tests is $97 per barrel in 2020 and is inflated at a rate of 2.5% per annum for the
remaining life of the asset. This long-term assumption is derived from the $80 per barrel real oil price assumption used for investment appraisal. In
the current price environment, the market prices used for the first five years of both value-in-use and fair value less costs of disposal impairment
tests are particularly volatile. Market prices used for the first five years of both value-in-use and fair value less costs of disposal impairment tests are
shown in the table below:

Brent oil price ($/bbl)
Henry Hub natural gas price ($/mmBtu)

2015

61
3.11

2014

108
3.86

2016

69
3.53

2015

102
4.02

2017

73
3.82

2016

97
4.10

2018

76
4.00

2017

93
4.17

2014

2019

77
4.15

2013

2018

90
4.27

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. In 2014 the discount rate used for value-in-use calculations was
12% nominal (2013 12% nominal), with a 2% premium added in higher-risk countries. The discount rates applied in assessments of impairment are
reassessed each year. Reserves assumptions for value-in-use tests are confined to proved and sanctioned probable reserves. For value-in-use
calculations, prices for oil and natural gas used for future cash flow calculations are based on market prices for the first five years (consistent with
those shown in the table above) and the group’s flat nominal long-term price assumptions thereafter. As at 31 December 2014, the group’s long-
term flat nominal price assumptions were $90 per barrel for Brent and $6.50/mmBtu for Henry Hub (2013 $90 per barrel and $6.50/mmBtu). These
long-term price assumptions are subject to periodic review and revision.

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 $11.9 billion on its balance sheet (2013 $12.2 billion), principally relating to the Atlantic
Richfield, Burmah Castrol, Devon Energy and Reliance transactions. In testing goodwill for impairment, the group uses the approach described
above to determine recoverable amount. 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 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 3 and details on the carrying amounts of assets are shown
in Note 10, Note 12 and Note 13.

Inventories
Inventories, other than inventories 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, adjusted where the sale of inventories after the reporting period gives evidence
about their net realizable value at the end of the period.

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.

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Leases
Finance leases 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.

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 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
These 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 measured at amortized cost using the effective interest method, less any impairment.

Available-for-sale 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, and, for available-for-sale debt instruments, 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 loans and receivables
The group assesses at each balance sheet date whether a financial asset or group of financial assets is impaired. 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: recoverability of trade receivables
Judgements are required in assessing the recoverability of overdue trade receivables 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 27 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.

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.

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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. These 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 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. 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 attributable to either 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. The group applies fair value hedge
accounting when hedging interest rate risk on fixed rate borrowings.

If the criteria for hedge accounting are no longer met, or if the group revokes the designation, the accumulated adjustment to the carrying amount of a
hedged item at such time is then amortized to profit or loss over the remaining period to maturity.

Cash flow hedges
The effective portion of the gain or loss on a cash flow 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 reclassified to the income statement when the hedged
transaction affects profit or loss.

Where the hedged item is a non-financial asset or liability, such as a forecast foreign currency transaction for the purchase of property, plant and
equipment, the amounts recognized within other comprehensive income are reclassified to the initial carrying amount of the non-financial asset or
liability. Where the hedged item is an equity investment, the amounts recognized in other comprehensive income remain in the separate component of
equity until the hedged cash flows affect profit or loss. Where the hedged item is recognized directly in profit or loss, the amounts recognized in other
comprehensive income are reclassified to production and manufacturing expenses, except for cash flow hedges of variable interest rate risk which are
reclassified to finance costs.

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 reclassified to the
income statement or to the initial carrying amount of a non-financial asset or liability as above.

Significant estimate or judgement: application of hedge accounting
The decision as to whether to apply hedge accounting within subsidiaries, and by equity-accounted entities, can have a significant impact on the group’s
financial statements. Cash flow and fair value hedge accounting is applied to certain finance debt-related instruments in the normal course of business
and cash flow hedge accounting is applied to certain highly probable foreign currency transactions as part of the management of currency risk. 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. The group 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 in 2013 and a pre-tax gain of $1,410 million in 2012. See Note 15, Note 27, and Note 28 for further details.

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: valuation of derivatives
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, as well as to the majority of the group’s
embedded derivatives. These embedded derivatives arise primarily from long-term UK natural gas contracts that use pricing formulae not related to
gas prices, for example, oil product and power prices. The majority of 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 28.

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. 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 are considered when assessing whether
a current legally enforceable right to set off exists.

Provisions, contingencies and reimbursement assets
Provisions are recognized when the group has a present legal or constructive obligation 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. A provision is discounted using either a nominal discount rate of 2.75% (2013 3.25%) or a real discount rate of
0.75% (2013 1%), as appropriate. 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
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.

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Significant estimate or judgement: provision relating to the Gulf of Mexico oil spill
Detailed information on the Gulf of Mexico oil spill, including the financial impacts, is provided in Note 2.

The provision recognized is the reliable estimate of expenditures required to settle certain present obligations at the end of the reporting period.
There are future expenditures, however, 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 the assumption that BP did not act with gross negligence or engage in wilful misconduct. However, in September 2014 the district court ruled
that the discharge of oil was the result of BP’s gross negligence and wilful misconduct and it is not now possible to determine a reliable estimate of
the liability. The existing provision has been maintained as explained in Note 2 and a contingent liability has been disclosed in relation to the potential
for a higher penalty due to this ruling. The amount that will become payable by BP is subject to a very high level of uncertainty since it will depend
on the outcome of BP’s appeal of the September 2014 gross negligence ruling as well as what is determined by the court in the federal multi-district
litigation proceedings in New Orleans (MDL 2179) with respect to the application of statutory penalty factors. See Note 2 for additional information.

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. The provision for the costs of decommissioning wells, production facilities and pipelines at the end of their
economic lives is estimated using existing technology, at current prices or future assumptions, depending on the expected timing of the activity, and
discounted using the real discount rate. The weighted average period over which these costs are generally expected to be incurred is estimated to be
approximately 20 years.

An amount equivalent to the decommissioning provision is recognized as part of the corresponding intangible asset (in the case of an exploration or
appraisal well) or property, plant and equipment. The decommissioning portion of the property, plant and equipment is subsequently depreciated at the
same rate as the rest of the asset.

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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.

Environmental expenditures and liabilities
Environmental expenditures that are required in order for the group to obtain future economic benefits from its assets are capitalized as part of those
assets. 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 to settle the obligation. Provisions for environmental liabilities have been
estimated using existing technology, at current prices and discounted using a real discount rate. The weighted average period over which these costs
are generally expected to be incurred is estimated to be approximately five years.

Significant estimate or judgement: provisions
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 occurs are uncertain. Decommissioning technologies and costs are constantly changing, as well as
political, environmental, safety and public expectations. BP believes that the impact of any reasonably foreseeable change 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. 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 the 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 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 2014 was a real rate of 0.75% (2013 1.0%), which was based on long-dated US
government bonds.

Provisions and contingent liabilities relating to the Gulf of Mexico oil spill are discussed in Note 2. Information about the group’s other provisions is
provided in Note 21. As further described in Note 21, 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.

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 balance sheet date 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. A
corresponding credit is recognized within equity. Fair value is determined by using an appropriate, widely used, 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 any remaining
unrecognized cost is expensed.

Cash-settled transactions
The cost of cash-settled transactions is recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding
liability which is recognized on the balance sheet. The liability is remeasured at fair value at each balance sheet date until settlement, with changes in
fair value recognized in the income statement.

Pensions and other post-retirement benefits
The cost of providing benefits under the group’s 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, which is recognized in the income statement, 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.

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Remeasurements of the defined benefit liability and 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 and are not
subsequently reclassified to profit and loss.

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. Defined benefit pension plan
surpluses are only recognized to the extent they are recoverable.

Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.

Significant estimate or judgement: pensions and other post-retirement benefits
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 and assumptions for
inflation rates.

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.

The assumptions used are provided in Note 22.

The discount rate and inflation 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 22.

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 22.

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.

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 and associates and interests in joint arrangements, 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 and associates and interests in
joint arrangements, 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.

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BP Annual Report and Form 20-F 2014

109

1. Significant accounting policies, judgements, estimates and assumptions – continued

Significant estimate or judgement: income taxes
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 7.

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 taxes 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 are shown as deductions from shareholders’ equity at cost. For accounting purposes, own equity
instruments include both treasury shares and shares purchased from the open market. Some of these own equity instruments are held by Employee
Share Ownership Plans (ESOPs), including certain shares transferred out of treasury. Consideration, if any, 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, but are shown as a deduction from the profit and loss
account 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.

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.

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
There are no new or amended standards or interpretations adopted during the year that have a significant impact on the financial statements.

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.

The IASB issued IFRS 15 ‘Revenue from Contracts with Customers’, which provides a single model for accounting for revenue arising from contracts
with customers and is effective for annual periods beginning on or after 1 January 2017. IFRS 15 will supersede IAS 18 ‘Revenue’.

The IASB has also issued IFRS 9 ‘Financial Instruments’, which will supersede IAS 39 ‘Financial Instruments: Recognition and Measurement’ and is
effective for annual periods beginning on or after 1 January 2018. IFRS 9 covers classification and measurement of financial assets and financial
liabilities, impairment methodology and hedge accounting.

BP has not yet decided the date of adoption for the group for IFRS 15 and IFRS 9 and has not yet completed its evaluation of the effect of adoption.
The EU has not yet adopted IFRS 15 or IFRS 9.

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.

110

BP Annual Report and Form 20-F 2014

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 $43.5 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 and the
measurement of the penalty obligation under the Clean Water Act, 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 48 and Legal proceedings on page 228.

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
Accruals
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

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2014

2013

781

(781)
38

(819)
262

(557)

430

(430)
39

(469)
73

(396)

$ million

2012

4,995

(4,995)
19

(5,014)
94

(4,920)

1,154

2,457

(655)
(1,702)

(1,203)

(1,030)
(2,951)

(1,524)

2,701

2,442

(2,412)
(169)
(6,903)
1,723

(5,060)

(2,986)
–
(6,395)
2,748

(4,191)

(6,263)

(5,715)

(819)
38
939
(662)
(792)

(1,296)

(469)
39
1,129
(1,481)
(618)

(1,400)

(5,014)
19
4,834
(998)
(5,090)

(6,249)

The impact on net cash provided by operating activities, on a post-tax basis, amounted to an outflow of $9 million (2013 outflow of $73 million and
2012 outflow of $2,382 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) – 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 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

BP Annual Report and Form 20-F 2014

111

2. Significant event – Gulf of Mexico oil spill – continued

payments will be made directly from the trust fund, and BP will be released from its corresponding obligation. The reimbursement asset is recorded
within Trade and other receivables on the balance sheet apportioned between current and non-current elements. The net increase in the provision for
items covered by the trust fund of $662 million relates principally to business economic loss claims as well as increases in the provision for claims
administration costs. During the year, cumulative charges to be paid by the Trust reached $20 billion. Subsequent additional costs, over and above
those provided within the $20 billion, are being expensed to the income statement as incurred.

At 31 December 2014, $3,855 million of the provisions and payables are eligible to be paid from the Trust. The table below shows movements in the
reimbursement asset during the period to 31 December 2014.

At 1 January
Net Increase in provision for items covered by the trust fund
Amounts paid directly by the trust fund

At 31 December

Of which – current

– non-current

2014

4,899
662
(1,706)

3,855

1,154
2,701

2013

6,442
1,542
(3,085)

4,899

2,457
2,442

$ million

Cumulative since the
incident

–
20,000
(16,145)

3,855

1,154
2,701

As at 31 December 2014, the aggregate cash balances in the Trust and the QSFs amounted to $5.1 billion, including $1.1 billion remaining in the
seafood compensation fund which has yet to be distributed and $0.4 billion held for natural resource damage early restoration. A further $500-million
partial distribution from the seafood compensation fund has been recommended and disbursement of funds commenced in early 2015. The portion of
the provision and reimbursement asset that related to the seafood compensation fund were derecognized upon funding of the seafood compensation
fund QSF in 2012.

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. 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 228.

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 agreed to pay $4 billion over a period of five years. At 31 December 2014, the remaining criminal claims
payable, within Other payables, was $2,995 million, of which $595 million falls due in 2015.

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, with the final instalment paid during 2014.

Provisions and contingent liabilities

Provisions
BP has recorded provisions relating to the Gulf of Mexico oil spill in relation to environmental expenditure (including 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 in provision
Unwinding of discount
Change in discount rate
Utilization – paid by BP

– paid by the trust fund

At 31 December

Of which – current

– non-current

Net increase in provision
Unwinding of discount
Change in discount rate
Reclassified to other payables
Utilization – paid by BP

– paid by the trust fund

At 31 December 2014

Environmental

Litigation
and Claims

Clean Water
Act

1,679
190
1
2
(83)
(648)

1,141

528
613

4,157
1,137
–
–
(307)
(1,033)

3,954

1,174
2,780

3,510
–
–
–
–
–

3,510

–
3,510

$ million

2014

Total

9,346
1,327
1
2
(390)
(1,681)

8,605

1,702
6,903

$ million

Cumulative since the incident

Environmental

Litigation
and Claims

Clean Water
Act

14,599
13
19
–
(11,687)
(1,803)
1,141

26,595
6
–
(4,283)
(4,080)
(14,284)
3,954

3,510
–
–
–
–
–
3,510

Total

44,704
19
19
(4,283)
(15,767)
(16,087)
8,605

Environmental
The environmental provision at 31 December 2014 includes the remaining $279 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

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2. Significant event – Gulf of Mexico oil spill – continued

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 into 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 and during 2014, Phase 3 of the early restoration projects was formally agreed, comprising $627 million of approved project
spend (of which $563 million has been paid). At 31 December 2014, the remaining amount provided for natural resource damage assessment costs
and early restoration projects was $798 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.

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, under OPA 90 and other legislation (‘State and Local Claims’), except as described under Contingent
liabilities below. Claims administration costs and legal costs, including legal costs under indemnification agreements, have also been provided for.
The timing of payment of litigation and claims provisions classified as non-current is dependent upon ongoing 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, which are provided for where an eligibility notice had been issued before the end of the month following the balance sheet date and is not
subject to appeal by BP within the claims facility. As disclosed in BP Annual Report and Form 20-F 2013, 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 Economic and
Property Damages Settlement Agreement (EPD Settlement Agreement) by the claims administrator that BP believes was incorrect.

During 2014, there were various rulings 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.

In March 2014, the US Court of Appeals for the Fifth Circuit (the Fifth Circuit) affirmed the district court’s ruling that the EPD Settlement Agreement
contained no causation requirement beyond the revenue and related tests set out in an exhibit to that agreement. In March 2014, BP filed a petition
that all the active judges of the Fifth Circuit review the decision; in May 2014 this was denied. The district court dissolved the injunction that had halted
the processing and payment of business economic loss claims and instructed the claims administrator to resume the processing and payment of
claims. BP sought review by the US Supreme Court (Supreme Court) of the Fifth Circuit’s decisions relating to compensation of claims for losses with
no apparent connection to the Deepwater Horizon spill. In December 2014, the Supreme Court declined to review BP’s petition. As a result, the final
deadline for filing claims in the Economic and Property Damages Settlement is 8 June 2015.

Management believes that no reliable estimate can currently be made of any business economic loss claims (i) not yet received; (ii) received, but not yet
processed; or (iii) processed, but not yet paid, except where an eligibility notice had been issued before the end of the month following the balance sheet
date and is not subject to appeal by BP within the claims facility. The inability to estimate reliably such claims is due to uncertainty regarding both the
volume of such claims and the average value per claim.

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In respect of uncertainty regarding the volume of claims, in December 2014, the Supreme Court declined to hear BP’s appeal of the district court ruling
that the EPD Settlement Agreement contained no causation requirement beyond the revenue and related tests set forth in that agreement. This
resolution, however, does not reduce uncertainty in the short term regarding the volume of claims, since it is possible that additional claims will be
made. In addition, a claims submission deadline of 8 June 2015 has now been set, which may lead to an increase in the rate of claims received until
the deadline, compounding management’s inability to estimate the total volume of claims that will be made.

In respect of uncertainty regarding the average value per claim, a small proportion of the filed claims have been determined under the revised policy for
the matching of revenue and expenses for business economic loss claims (introduced in May 2014) and disputes, disagreements, and uncertainties
regarding the proper application of the revised policy to particular claims and categories of claims continue to arise as the claims administrator has
begun applying the revised policy. Furthermore, there have been no, or only a small number of, claim determinations made under some of the
specialized frameworks that have been put in place for particular industries and so determinations to date may not be representative of the total
population of claims. In addition, due to a data secrecy order, detailed data about claims that have not yet been determined is not currently available to
BP and so it is not possible to review claim demographics or identify potential populations for each category of claim.

There is therefore very little data to build up a track record of claims determinations under the policies and protocols that are now being applied
following resolution of the matching and causation issues. We therefore cannot estimate future trends of the number and proportion of claims that will
be determined to be eligible, nor can we estimate the value of such claims. A provision for such business economic loss claims will be established
when these uncertainties are resolved and a reliable estimate can be made of the liability.

The current estimate for the total cost of those elements of the PSC settlement that BP considers can be reliably estimated is $9.9 billion. The
DHCSSP has issued eligibility notices, most of which are disputed by BP, in respect of business economic loss claims of approximately $400 million
which have not been provided for. The majority of these claims are being re-assessed using the new matching policy. 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 total
cost of the PSC settlement is likely to be significantly higher than the amount recognized to date of $9.9 billion because the current estimate does not
reflect business economic loss claims not yet received, or received but not yet processed, or processed but not yet paid, except where an eligibility
notice had been issued before the end of the month following the balance sheet date and is not subject to appeal by BP within the claims facility.

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.

Significant uncertainties exist in relation to the amount of claims that are to be paid and will become payable, including claims payable under the
DHCSSP and State and Local Claims. There is significant uncertainty in relation to the amounts that ultimately will be paid in relation to current claims,
and the number, type and amounts payable for claims not yet reported as described above and in Legal proceedings on page 228 and the outcomes of
any further litigation including in relation to potential opt-outs from the PSC settlement or otherwise. There is also uncertainty as to the cost of
administering the claims process under the DHCSSP and in relation to future legal costs.

See Legal proceedings on page 228 and Contingent liabilities below for further details.

BP Annual Report and Form 20-F 2014

113

2. Significant event – Gulf of Mexico oil spill – continued

Clean Water Act penalties
A provision of $3,510 million was recognized in 2010 for estimated civil penalties under Section 311 of the Clean Water Act. At the time the provision
for the Clean Water Act penalty was made, the number of barrels of oil spilled was determined by using the mid-point (47,500 barrels per day) of the
range of estimates (35,000 to 60,000 barrels per day) from the intra-agency Flow Rate Technical Group created by the National Incident Commander in
charge of the spill response. The initial 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.

The estimates of cumulative discharge presented by experts testifying in the Phase 2 trial varied significantly. In January 2015, the district court issued
its decision in the Phase 2 trial that 3.19 million barrels of oil were discharged into the Gulf of Mexico and therefore subject to a Clean Water Act
penalty. This amount is consistent with the number of barrels BP has used to calculate the provision. In addition, the district court found that BP was
not grossly negligent in its source control efforts. BP and other parties to the proceedings have filed notices of appeal of the Phase 2 ruling and
therefore the findings from the Phase 2 trial remain subject to uncertainty.

In September 2014, the district court issued its decision in the Phase 1 trial that the discharge of oil was the result of the gross negligence and wilful
misconduct of BP Exploration & Production Inc. (BPXP) and that BPXP is therefore subject to enhanced civil penalties. The statutory maximum penalty
is up to $4,300 per barrel of oil discharged where gross negligence or wilful misconduct is proven. BP does not believe that the evidence at trial
supports a finding of gross negligence and wilful misconduct and in December 2014 filed notice of appeal of the Phase 1 ruling.

As a result of the September 2014 district court ruling that the discharge of oil was the result of BP’s gross negligence and wilful misconduct, the
Clean Water Act penalty obligation is not considered to be reliably measurable and it is therefore no longer possible to determine a best estimate of the
Clean Water Act penalty provision. Under IFRS, a provision is reversed when it is no longer probable that an outflow of resources will be required to
settle the obligation. With regard to the Clean Water Act penalty obligation, it continues to be probable that there will be an outflow of resources and
therefore, in the absence of the ability to identify the best estimate of the liability, the previously recognized provision of $3,510 million has been
maintained. Note 1 – Provisions, contingencies and reimbursement assets identifies the significant accounting estimates and judgements made in
relation to the Clean Water Act provision.

BP continues to believe that a provision of $3,510 million represents a reliable estimate of the amount of the liability if the appeal is successful. If BP is
unsuccessful in its appeal, and the ruling of gross negligence and wilful misconduct is upheld, the maximum penalty that could be imposed is up to
$4,300 per barrel. Based upon this penalty rate and the district court’s ruling on the number of barrels spilled, which, as noted above is also subject to
appeal, the maximum penalty could be up to $13.7 billion.

However, in assessing the amount of the penalty, the court is directed to consider the following statutory penalty factors: ‘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’. The court has wide
discretion in deciding how to apply these factors to determine the penalty and what weighting to ascribe to different factors. BP is therefore unable to
ascribe probabilities to possible outcomes within the range of potential penalties and cannot determine a reliable estimate for any additional penalty
which might apply should the gross negligence finding be upheld. The trial phase to determine the amount of the Clean Water Act penalty commenced
on 20 January 2015.

The amount that may become payable by BP is subject to a very high level of uncertainty since it will depend on the outcome of BP’s appeals as well
as what is determined by the district court with respect to the application of statutory penalty factors as noted above. The court has wide discretion in
the application of statutory penalty factors. The timing of any payment is also uncertain.

Given the significant uncertainty, the very wide range of possible outcomes if BP is unsuccessful in this appeal of the September ruling, and the
inability to ascribe probabilities to possible outcomes within the range, management is not able to estimate reliably any further liability for the Clean
Water Act penalty arising in the event that BP is not successful in its appeal. A contingent liability is therefore disclosed. See Contingent liabilities
below for further information.

Provision movements
The total amount recognized as an increase in provisions during the year was $1,327 million. After deducting amounts utilized during the year totalling
$2,071 million, including payments from the trust fund of $1,681 million and payments made directly by BP of $390 million (2013 $3,777 million,
including payments from the trust fund of $3,051 million and payments made directly by BP of $726 million), and after adjustments for discounting, the
remaining provision as at 31 December 2014 was $8,605 million (2013 $9,346 million).

The total amounts that will ultimately be paid by BP for 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, 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 that can be measured reliably. It is not possible, at this time, to measure reliably
other obligations arising from the incident, 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 2014.

114

BP Annual Report and Form 20-F 2014

2. Significant event – Gulf of Mexico oil spill – continued

Natural resource damage claims
As described above in Provisions, a provision has been made for natural resource damage assessment and early restoration projects under the
$1-billion framework agreement. 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 damage claims and associated legal
costs, therefore no such amounts have been provided as at 31 December 2014.

Business economic loss claims under the PSC settlement
BP 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. The potential cost of business economic loss claims not yet
received, processed and paid (except where an eligibility notice had been issued before the end of the month following the balance sheet date and is
not subject to appeal by BP within the claims facility) 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. See Provisions above
for further information.

State and Local claims
As described above in Provisions, a provision has been made for State and Local claims that can be measured reliably. The States of Alabama,
Mississippi, Florida, Louisiana and Texas 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. 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. 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; the timing of any outflow of resources in relation to State
and Local claims is dependent on the timing of the court process in relation to these claims.

Clean Water Act penalties
A provision has been maintained for BP’s obligation under the Clean Water Act, as described above in Provisions. Any obligation in relation to any
further liability for the Clean Water Act penalty arising in the event that BP is not successful in its appeal of the Phase 1 ruling is disclosed as a
contingent liability. The trial phase to determine the amount of the Clean Water Act penalty commenced in January 2015 and post-trial briefing is
scheduled to complete in April 2015. BP does not know when the district court will rule on the Penalty Phase of the trial and so the timing of any
payment continues to be uncertain.

Securities-related litigation
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 Depositary Shares under US federal securities law, are continuing. A jury trial is scheduled to begin in January 2016 and the timing of any
outflow of resources, if any, is dependent on the duration of the court process. 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 2014. In addition, no reliable estimate can be made of the
amounts that may be payable in relation to any other securities litigation, if any, so no provision has been recognized at 31 December 2014.

Other litigation
In addition to the State and Local claims and securities class actions described above, BP is named as a defendant in approximately 3,000 other civil
lawsuits brought by individuals, corporations and government entities in US federal and state courts, as well as certain non-US 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. In addition, claims have been received, primarily from business claimants, under OPA 90 in relation to the
2010 federal deepwater drilling moratoria. 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, nor it is possible to
determine the timing of any payment that may arise. Therefore no amounts have been provided for these items as at 31 December 2014.

It is not possible to measure reliably any obligation in relation to other litigation or potential fines and penalties. 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.

Settlement and other agreements
Under the settlement agreements with Anadarko and MOEX, and with Cameron International, the designer and manufacturer of the Deepwater
Horizon blowout preventer, BP has agreed to indemnify Anadarko, MOEX and Cameron 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, nor identify the timing of, any obligation
in relation to such claims and therefore no amount has been provided as at 31 December 2014. There are also agreements indemnifying certain third-
party contractors in relation to litigation costs and certain other claims. A contingent liability is also disclosed in relation to other obligations under these
agreements.

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 48. 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.

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2. Significant event – Gulf of Mexico oil spill – continued

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
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

2014

1,327
2
114
–
–
(662)
–

781
38

819

2013

1,860
(5)
136
–
–
(1,542)
(19)

430
39

469

$ million

Cumulative since
the incident

44,705
19
4,358
19,580
283
(20,000)
(5,681)

43,264
231

43,495

2012

6,074
–
257
–
–
(1,191)
(145)

4,995
19

5,014

The group income statement for 2014 includes a pre-tax charge of $819 million (2013 pre-tax charge of $469 million) in relation to the Gulf of Mexico oil
spill. The costs charged in 2014 relate primarily to the ongoing costs of operating the Gulf Coast Restoration Organization (GCRO) and increases in the
provisions for natural resource damage assessment, business economic loss claims, claims administration costs, legal and litigation costs. Finance
costs of $38 million (2013 $39 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 and estimated obligations for future costs
that can be estimated reliably at this time, 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, net
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

2014

–
–
(662)
–

(662)

190
2
–

192

–
–

–

1,137
–

1,137

–
114
–

781
38

819

2013

–
–
(1,542)
–

(1,542)

47
(5)
–

(113)
–

(113)

1,926
–

1,926

–
136
(19)

430
39

469

$ million

Cumulative since
the incident

19,580
283
(20,000)
8

(129)

3,134
19
70

3,223

11,465
2,839

14,304

26,596
184

26,780

3,510
1,257
(5,681)

43,264
231

43,495

2012

–
–
(1,191)
–

(1,191)

801
–
–

801

109
9

118

5,164
–

5,164

–
248
(145)

4,995
19

5,014

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.

116

BP Annual Report and Form 20-F 2014

3. 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

2014

2013

405
474
–
16

895

371
214
12,500
30

13,115

2014

2013

345
401
3

749

6,737
1,264
317

8,318

(102)
–
–

(102)

144
78
8

230

1,255
484
218

1,957

(226)
–
–

(226)

$ million

2012

6,504
152
–
41

6,697

$ million

2012

109
195
6

310

3,046
2,892
320

6,258

(289)
(1)
(3)

(293)

Impairment and losses on sale of businesses and fixed assets

8,965

1,961

6,275

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. By 31 December 2012, the group had announced disposals of $38 billion, and in addition, announced the sale of our 50%
investment in TNK-BP. During 2013, the group announced that it expected to divest a further $10 billion of assets before the end of 2015. BP had
agreed around $4.7 billion of such further divestments and received proceeds of $3.6 billion as at 31 December 2014.

Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposed

By business
Upstream
Downstream
TNK-BP
Other businesses and corporate

2014

1,820
1,671

3,491

2,533
864
–
94

3,491

2013

18,115
3,884

21,999

1,288
3,991
16,646
74

21,999

$ million

2012

9,992
1,606

11,598

10,667
637
–
294

11,598

At 31 December 2014, deferred consideration relating to disposals amounted to $1,137 million receivable within one year (2013 $23 million and 2012
$24 million) and $333 million receivable after one year (2013 $1,374 million and 2012 $1,433 million). In addition, contingent consideration relating to
the disposals of the Devenick field and the Texas City refinery amounted to $454 million at 31 December 2014 (2013 $953 million) – see Notes 16 and
28 for further information.

Upstream
In 2014, gains principally resulted from the sale of certain onshore assets in the US, and the sale of certain interests in the Gulf of Mexico and the
North Sea. Losses principally arose from adjustments to prior year disposals in Canada and the North Sea.

In 2013, gains principally resulted from the sale of certain of our interests in the central North Sea, and the Yacheng field in China.

In 2012, gains principally resulted from the sale of certain interests in the Gulf of Mexico and certain onshore assets in the US, the sale of our interests
in our Canadian natural gas liquids business, and the sale of a number of interests in the North Sea.

Downstream
In 2014, gains principally resulted from the disposal of our global aviation turbine oils business. Losses principally arose from costs associated with the
decision to cease refining operations at Bulwer Island in Australia.

BP Annual Report and Form 20-F 2014

117

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In 2013, gains principally 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.

In 2012, gains principally resulted from the disposal of our interests in purified terephthalic acid production in Malaysia, and retail churn in the US.
Losses principally resulted from costs associated with our US refinery divestments.

TNK-BP
In 2013, BP disposed of its 50% interest in TNK-BP to Rosneft, resulting in a gain on disposal of $12,500 million.

Summarized financial information relating to the sale of businesses is shown in the table below. The principal transaction categorized as a business
disposal in 2014 was the sale of certain of our interests on the North Slope of Alaska in our upstream business, which had been classified as held for
sale during 2014. 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

Gains on sale of businesses
Total consideration
Consideration received (receivable)b
Proceeds from the sale of businesses related to completed transactions
Deposits received related to assets classified as held for sale
Disposals completed in relation to which deposits had been received in prior year
Proceeds from the sale of businessesc

2014

1,452
182
(395)
(65)
1,174
(7)
128
1,295
280
1,575
96
1,671
–
–
1,671

2013

2,124
2,371
(94)
(62)
4,339
23
13
4,375
69
4,444
(414)
4,030
–
(146)
3,884

$ million

2012

610
570
(263)
(232)
685
(15)
39
709
675
1,384
76
1,460
146
–
1,606

a 2013 includes pension and other post-retirement benefit plan curtailment gains of $109 million.
b 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.

c 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 $32 million (2013 $42 million and 2012

$4 million).

Impairments
Impairment losses in each segment are described below. For information on significant estimates and judgements made in relation to impairments see
Impairment of property, plant and equipment, intangibles and goodwill within Note 1.

Upstream
The 2014 impairment losses of $6,737 million included $4,876 million in the North Sea business, of which $1,964 million related to the Valhall cash-
generating unit (CGU), $660 million related to the Andrew area CGU, and $515 million related to the ETAP CGU. These CGUs have recoverable amounts of
$767 million, $1,431 million, and $1,753 million respectively. Impairment losses also included an $859-million impairment of our PSVM CGU in Angola to its
recoverable amount of $1,964 million, and a $415-million impairment of the Block KG D6 CGU in India to its recoverable amount of $2,364 million. The
recoverable amount of the Block KG D6 CGU is stated after the exploration write-off described in Note 6. All of the impairments relate to producing assets.
The impairments in the North Sea and Angola arose as a result of a lower price environment in the near term, technical reserves revisions, and increases in
expected decommissioning cost estimates. The impairment of Block KG D6 arose following the introduction of a new formula for Indian gas prices. The
recoverable amounts of the Valhall and Block KG D6 CGUs are their fair values less costs of disposal based on the present value of future cash flows, a
level-3 valuation technique in the fair value hierarchy. The key assumptions in the tests were oil and natural gas prices, production volumes and the discount
rate. The recoverable amounts of the Andrew area CGU, the ETAP CGU and the PSVM CGU are their values in use. See Impairment of property, plant and
equipment, intangible assets and goodwill within Note 1 for further information on assumptions used for impairment testing. The discount rate used to
determine the value in use of the PSVM CGU included the 2% premium for higher-risk countries as described in Note 1. A premium was not applied in
determining the recoverable amount of the other CGUs.

The main elements of the 2013 impairment losses of $1,255 million were a $251-million impairment loss relating to the Browse project in Australia and
a $253-million aggregate write-down of a number of assets in the North Sea, caused by increases in expected decommissioning costs. Impairment
reversals arose on certain of our interests in Alaska, the Gulf of Mexico, and the North Sea, triggered by reductions in decommissioning provisions due
to continued review of the expected decommissioning costs and an increase in the discount rate for provisions.

The main elements of the 2012 impairment losses of $3,046 million were a $1,082-million write-down of our interests in certain 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. Impairment reversals principally arose on certain of our interests in the Gulf of Mexico, triggered by a decision to divest assets.

Downstream
The main elements of the 2014 impairment losses of $1,264 million related to our Bulwer Island refinery and certain midstream assets in our fuels
business, and certain manufacturing assets in our petrochemicals business.

The main elements of the 2013 impairment losses of $484 million related to impairments of certain refineries in the US and elsewhere in our global
fuels portfolio.

The main elements of the 2012 impairment losses of $2,892 million related to assets held for sale for which sales prices had been agreed. This 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.

118

BP Annual Report and Form 20-F 2014

3. Disposals and impairment – continued

Other businesses and corporate
Impairment losses totalling $317 million, $218 million, and $320 million were recognized in 2014, 2013 and 2012 respectively. The amount for 2014 is
principally in respect of our biofuels businesses in the UK and US. The amount for 2013 is principally in respect of our US wind business. The amount
for 2012 is principally in respect of the decision not to proceed with an investment in a biofuels production facility under development in the US.

4. Segmental analysis

The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2014, 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 biofuels and wind businesses, the group’s shipping and treasury functions, and corporate activities
worldwide.

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. 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 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 group subsidiary which made the sale. 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 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.

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a Inventory holding gains and losses represent the difference between the cost of sales calculated using the replacement cost of inventory 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 historical 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 based on the replacement cost of inventory. For this purpose, the replacement cost of inventory is calculated using data from each
operation’s production and manufacturing system, either on a monthly basis, or separately for each transaction where the system allows this approach. 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 2014

119

4. Segmental analysis – continued

By business

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

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 amortizationb

US
Non-US

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 assetsc

Additions to other investments
Element of acquisitions not related to non-current

assets

Additions to decommissioning asset

Capital expenditure and acquisitions

Upstream

Downstream

Rosneft

Other
businesses
and
corporate

Gulf of
Mexico
oil spill
response

Consolidation
adjustment
and
eliminations

$ million

2014

Total
group

65,424

323,486

(36,643)

28,781
1,089

173

323,659
265

–

–
2,101

1,989

(861)

1,128
(83)

–

–
–

(37,331)

353,568

37,331

–

–
–

353,568
3,372

8,934
(86)

8,848

3,738
(6,100)

(2,362)

2,100
(24)

2,076

(2,010)
–

(2,010)

(781)
–

(781)

641
–

641

12,622
(6,210)

6,412

(1,148)

(314)

4,950

5,210
9,953
(430)

2,625

19,156

26,492

160

(366)
(2,505)

–
–
–

–

23,781

4,129
8,404
(430)

260

7,877

22,587

984
1,336
–

713

3,244

3,121

19,772

3,106

–
–
–

–

7,312

–

97
213
–

323

723

784

903

–
–
–

1,329

–

a See explanation of inventory holding gains and losses on page 119.
b It is estimated that the benefit arising from the absence of depreciation for the assets held for sale during the year was $221 million.
c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

120

BP Annual Report and Form 20-F 2014

4. Segmental analysis – continued

By business

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

between segments

Third party sales and other operating revenues
Equity-accounted earnings

70,374

351,195

(42,327)

28,047
1,027

(1,045)

350,150
195

–

–
2,058

–

–
–

1,805

(866)

939
(91)

–

–
–

(44,238)

379,136

44,238

–

–
–

379,136
3,189

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

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 amortizationb

US
Non-US

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 assetsc

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
(459)

2,581

25,835

36,916

39
(384)

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m
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s

–
–
–

–

3,538
7,514
(459)

747
1,343
–

161

270

–
–
–

–

7,780

19,499

3,302

13,681

4,449

11,941

–
–
–

–

181
187
–

–
–
–

295

1,855

1,072

1,027

1,050

–

Capital expenditure and acquisitions

19,115

4,506

11,941

–

36,612

a See explanation of inventory holding gains and losses on page 119.
b 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.
c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

BP Annual Report and Form 20-F 2014

121

4. Segmental analysis – continued

By business

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

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 amortizationb

US
Non-US

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 assetsc

Additions to other investments
Element of acquisitions not related to non-current assets
Additions to decommissioning asset

Upstream

Downstream

TNK-BP

Other
businesses
and
corporate

Gulf of
Mexico
oil spill
response

Consolidation
adjustment
and
eliminations

$ million

2012

Total
group

72,225

346,391

–

–
2,986

(1,365)

345,026
101

2,864
(487)

2,377

3,373
(3)

3,370

(42,572)

29,653
915

22,491
(104)

22,387

3,437
6,918
(347)

586
1,343
–

897

141

7,329

22,603

3,212

5,246

1,985

(899)

1,086
(67)

(2,794)
–

(2,794)

213
190
–

505

1,071

1,419

1,435

–

–
–

(44,836)

375,765

44,836

–

–
–

375,765
3,935

(4,995)
–

(4,995)

(576)
–

(576)

–
–
–

6,074

–

–
–
–

–

20,363
(594)

19,769

(1,072)

(566)

18,131

4,236
8,451
(347)

7,617

11,612

29,268

33
(72)
(4,025)

25,204

–
–
–

–

Capital expenditure and acquisitions

18,520

5,249

a See explanation of inventory holding gains and losses on page 119.
b It is estimated that the benefit arising from the absence of depreciation for the assets held for sale amounted to approximately $435 million.
c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

122

BP Annual Report and Form 20-F 2014

4. Segmental analysis – continued

By geographical area

Revenues

Non-US

$ million

2014

Total

Third party sales and other operating revenuesa

122,951

230,617

353,568

Other income statement items

Production and similar taxes

Results

Replacement cost profit before interest and taxation

Non-current assets

Non-current assetsb c

Capital expenditure and acquisitions

a Non-US region includes UK $77,522 million.
b Non-US region includes UK $18,430 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

By geographical area

Revenues

690

2,268

2,958

5,251

7,371

12,622

69,125

114,462

183,587

7,227

16,554

23,781

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

Non-current assetsb c

Capital expenditure and acquisitions

a Non-US region includes UK $82,381 million.
b Non-US region includes UK $18,967 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

By geographical area

Revenues

1,112

5,935

7,047

3,114

28,945

32,059

70,228

124,439

194,667

9,176

27,436

36,612

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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

Non-current assetsb c

Capital expenditure and acquisitions

a Non-US region includes UK $75,364 million.
b Non-US region includes UK $17,545 million.
c Includes property, plant and equipment; goodwill; intangible assets; investments in joint ventures; investments in associates; and non-current prepayments.

5. Income statement analysis

Currency exchange losses charged to the income statementa

Expenditure on research and development

Finance costs

Interest payable
Capitalized at 1.94% (2013 2% and 2012 2.25%)b
Unwinding of discount on provisions and other payables

1,472

6,686

8,158

180

20,183

20,363

66,751

10,541

107,844

174,595

14,663

25,204

2014

663

1,025
(185)
308
1,148

2013

180

707

1,082
(238)
224
1,068

$ million

2012

106

674

1,234
(390)
228
1,072

a Excludes exchange gains and losses arising on financial instruments measured at fair value through profit or loss.
b Tax relief on capitalized interest is approximately $43 million (2013 $62 million and 2012 $93 million).

Interest and other income of $1,677 million in 2012 includes $709 million of dividends from TNK-BP.

BP Annual Report and Form 20-F 2014

123

6. 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.

For information on significant estimates and judgements made in relation to oil and natural gas accounting see Intangible assets within Note 1.

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

2014

2013

3,029
603

3,632

–
–

2,710
731

3,441

253
–

$ million

2012

745
730

1,475

–
(42)

19,344

20,865

23,434

227

212

287

19,117

20,653

23,147

2,870

603
2,786

4,464

731
4,275

5,176

730
5,010

a 2014 included a $544-million write-off relating to disappointing appraisal results of Utica shale in the US Lower 48 and the subsequent decision not to proceed with its development plans, a $524-million
write-off relating to the Bourarhat Sud block licence in the Illizi Basin of Algeria, a $395-million write-off relating to Block KG D6 in India and a $295-million write-off relating to the Moccasin discovery in
the deepwater Gulf of Mexico. 2013 included a $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 and 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 26.

The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2014 is shown in the table
below.

Carrying amount

$1-2 billion
$2-3 billion
$4-5 billion

7. Taxation
Tax on profit

Location

Angola; India
Canada; Egypt; Brazil
US – Gulf of Mexico

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

Tax charge on profit

4,444
48

4,492

(3,194)
(351)

(3,545)

947

5,724
61

5,785

529
149

678

6,463

6,880

2014

2013

$ million

2012

6,664
252

6,916

67
(103)

(36)

In 2014, the total tax credit recognized within other comprehensive income was $1,481 million (2013 $1,374 million charge and 2012 $270 million
credit). See Note 30 for further information. The total tax charge recognized directly in equity was $36 million (2013 $33 million credit and 2012
$6 million credit).

For information on significant estimates and judgements made in relation to taxation see Income taxes within Note 1.

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 2014 the UK statutory corporation tax rate reduced from 23% to 21% on profits arising from activities outside the North Sea.
For 2014, the items presented in the reconciliation are distorted as a result of the tax credits related to the impairment losses recognized in the year,
and the effect of the impairment losses on the profit for the year. In order to provide a more meaningful analysis of the effective tax rate for 2014,
the table also presents separate reconciliations for the group excluding the effects of the impairment losses, and for the effects of the impairment
losses in isolation. For 2013 and 2012, the effective tax rate is not affected significantly by impairment losses. See Note 3 for further information.

124

BP Annual Report and Form 20-F 2014

7. Taxation – continued

Profit (loss) before taxation

Tax charge (credit) on profit or loss

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
Items not deductible for tax purposes
Other

Effective tax rate

2014
excluding
impairments

2014
impacts of
impairments

13,166

5,036

38%

(8,216)

(4,089)

50%

$ million

2014

4,950

947

19%

2013

2012

30,221

18,131

6,463

21%

6,880

38%

% of profit before taxation

17
(5)
(2)
4
(4)
–
(1)
4
4
–

34
–
–
(3)
–
–
–
–
(2)
–

(11)
(14)
(6)
17
(10)
1
(1)
10
12
–

4
(2)
1
2
(2)
–
(8)
2
1
–

12
(5)
1
2
(2)
8
–
(1)
2
(3)

a For 2014 excluding impairments, jurisdictions which contribute significantly to this item are Angola, with an applicable statutory tax rate of 50%, Trinidad, with an applicable statutory tax rate of 55%

and the US with an applicable federal tax rate of 35%. For 2014, impairment charges have generated losses on which tax credits arise, mainly in Norway and the UK North Sea, with applicable statutory
tax rates of 78% and 62% respectively. For 2013 and 2012, jurisdictions which contribute significantly are Angola, the UK and Trinidad with rates as disclosed above.

b For 2013, this relates to the non-taxable gain on disposal of our investment in TNK-BP.

Legislation to reduce the UK supplementary charge tax rate applicable to profits arising in the North Sea is expected to be enacted in 2015. The
evaluation of the effect of this change for BP has not yet been completed.

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

Income statement

$ million

Balance sheet

2014

2013

2012

2014

2013

(2,178)
(272)
(1,278)

(3,728)

492
52
166
589
(1,397)
281

183

(3,545)

(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

(36)

29,062
–
2,445

31,507

(2,761)
(11,237)
(575)
(298)
(3,848)
(1,204)

(19,923)

11,584

13,893
2,309

31,551
284
3,653

35,488

(2,026)
(11,301)
(579)
(888)
(2,585)
(1,655)

(19,034)

16,454

17,439
985

The recognition of deferred tax assets of $1,467 million (2013 $67 million), in entities which have suffered a loss in either the current or preceding
period, is supported by forecasts which indicate that sufficient future taxable profits will be available to utilize such assets.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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
At 31 December

2014

16,454
122
(3,545)
(1,563)
36
80
11,584

$ million

2013

14,369
43
678
1,397
(33)
–
16,454

BP Annual Report and Form 20-F 2014

125

7. Taxation – continued

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

Deductible temporary differencesd
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entitiese

2014

2.1
20.1
18.0
2.0
17.9
1.0

$ billion

2013

1.8
18.0
16.3
1.7
11.2
1.1

a Substantially all the tax losses have no fixed expiry date.
b The UK unused 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 unused tax credits expire 10 years after generation and will all expire in the period 2015-2023.
d Deductible temporary differences of $1.0 billion are expected to expire in the period 2015-2021, the remainder do not have an expiry date.
e An amendment has been made to the comparative amount.

Impact of previously unrecognized deferred tax or write-down of deferred tax assets on current year charge

Current tax benefit relating to the utilization of previously unrecognized tax credits
Deferred tax benefit relating to the recognition of previously unrecognized tax credits
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset

8. Dividends

2014

0.2
–
0.2

2013

0.2
0.2
–

$ billion

2012

0.4
0.1
–

The quarterly dividend expected to be paid on 27 March 2015 in respect of the fourth quarter 2014 is 10.00 cents per ordinary share ($0.60 per
American Depositary Share (ADS)). The corresponding amount in sterling will be announced on 16 March 2015. 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 2015

Pence per share

Cents per share

2014

2013

2012

2014

2013

2012

2014

2013

$ million

2012

5.7065
5.8071
5.9593
6.3769

6.0013
5.8342
5.7630
5.8008

5.0958
5.1498
5.0171
5.5890

23.8498

23.3993

20.8517

9.50
9.75
9.75
10.00

39.00

10.00

9.00
9.00
9.00
9.50

8.00
8.00
8.00
9.00

36.50

33.00

1,426
1,572
1,122
1,728

5,850

1,817

1,621
1,399
1,245
1,174

5,441

1,211
1,448
1,417
1,216

5,294

The details of the scrip dividends issued are shown in the table below.

Number of shares issued (thousand)
Value of shares issued ($ million)

2014

165,644
1,318

2013

202,124
1,470

2012

138,406
982

The financial statements for the year ended 31 December 2014 do not reflect the dividend announced on 3 February 2015 and expected to be paid in
March 2015; this will be treated as an appropriation of profit in the year ended 31 December 2015.

9. Earnings per ordinary share

Basic earnings per share
Diluted earnings per share

2014

20.55
20.42

2013

123.87
123.12

Cents per share

2012

57.89
57.50

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 certain shares that will be
issuable in the future under employee share-based payment plans and treasury shares, which includes shares held by the Employee Share Ownership
Plan trusts (ESOPs).

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

126

BP Annual Report and Form 20-F 2014

2014

3,780
2
3,778

2013

23,451
2
23,449

$ million

2012

11,017
2
11,015

9. Earnings per ordinary share – continued

Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share-based payment plans

Shares thousand

2014

2013

2012

18,385,458
111,836

18,931,021
115,152

19,027,929
129,959

18,497,294

19,046,173

19,157,888

The number of ordinary shares outstanding at 31 December 2014, excluding treasury shares, and including certain shares that will be issuable in the
future under employee share-based payment plans was 18,199,882,744. Between 31 December 2014 and 17 February 2015, the latest practicable
date before the completion of these financial statements, there was a net decrease of 24,096,712 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, no further shares were repurchased following the
continuation of share buybacks announced on 29 April 2014.

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 pages 72–88.

The following table shows the number of shares potentially issuable under equity-settled 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
these plans at 31 December included in the diluted earnings per share is also shown.

Share options

Outstanding
Exercisable
Dilutive effect

2014

Weighted
average
exercise
price $

9.62
10.89
n/a

2013

Weighted
average
exercise
price $

7.71
10.01
n/a

Number of

optionsa b

thousand

286,725
127,290
23,169

Number of

optionsa b

thousand

113,206
86,211
5,570

a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2014 the quoted market price of one BP ordinary share was $6.35 (2013 $8.10).

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.

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Share plans

Vesting

Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years

Dilutive effect

2014

2013

Number of
sharesa
thousand

78,467
91,993
80,966
28,564
222

280,212

99,917

Number of
sharesa
thousand

35,442
120,056
115,387
14,231
123

285,239

95,014

a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

There has been a net increase of 31,318,880 in the number of potential ordinary shares in relation with employee share-based payment plans between
31 December 2014 and 17 February 2015.

BP Annual Report and Form 20-F 2014

127

10. Property, plant and equipment

Cost

At 1 January 2014
Exchange adjustments
Additions
Acquisitions
Transfers
Deletions

At 31 December 2014

Depreciation

At 1 January 2014
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Deletions

At 31 December 2014

Net book amount at 31

December 2014

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

Net book amount at 31

December 2013

Land
and land
improvements

Buildings

Oil and
gas
propertiesa

Plant,
machinery
and
equipment

Fixtures,
fittings and
office
equipment

Transportation

3,375
(284)
315
31
–
(22)

3,415

550
(5)
84
15
–
(5)

639

3,027
(105)
183
22
–
(66)

3,061

1,141
(46)
156
–
–
(54)

1,197

187,691
–
18,033
–
993
(6,203)

200,514

97,063
–
11,728
6,304
(19)
(3,901)

111,175

48,912
(1,737)
2,008
252
–
(620)

48,815

20,378
(989)
1,833
625
–
(489)

21,358

3,176
(93)
258
3
–
(313)

3,031

1,970
(56)
267
–
–
(198)

1,983

13,314
(44)
1,049
–
–
(500)

13,819

8,833
(27)
343
179
(83)
(312)

8,933

Oil depots,
storage
tanks and
service
stations

9,961
(871)
521
–
–
(565)

9,046

5,831
(550)
448
504
–
(509)

5,724

$ million

Total

269,456
(3,134)
22,367
308
993
(8,289)

281,701

135,766
(1,673)
14,859
7,627
(102)
(5,468)

151,009

2,776

1,864

89,339

27,457

1,048

4,886

3,322

130,692

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

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

3,346
5
299
–
–
(474)

3,176

2,119
7
278
–
–
–
(434)

1,970

13,436
(55)
51
–
–
(118)

13,314

8,409
(28)
347
160
(17)
–
(38)

8,833

9,629
(36)
625
–
–
(257)

9,961

5,485
(7)
502
35
–
–
(184)

5,831

249,474
(351)
20,039
8
4,365
(4,079)

269,456

124,143
(96)
13,243
1,361
(226)
365
(3,024)

135,766

2,825

1,886

90,628

28,534

1,206

4,481

4,130

133,690

Assets held under finance leases at net book
amount included above

At 31 December 2014
At 31 December 2013

Assets under construction included above

At 31 December 2014
At 31 December 2013

–
–

3
7

135
187

295
265

–
–

244
4

–
–

677
463

26,429
27,900

a For information on significant estimates and judgements made in relation to the estimation of oil and natural reserves see Property, plant and equipment within Note 1.

11. Capital commitments

Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at 31 December
2014 amounted to $15,635 million (2013 $13,705 million).

128

BP Annual Report and Form 20-F 2014

12. Goodwill and impairment review of goodwill

Cost

At 1 January
Exchange adjustments
Acquisitions
Deletions

At 31 December

Impairment losses
At 1 January
Impairment losses for the year
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

2014

12,851
(278)
73
(164)

12,482

670
–
(56)

614

$ million

2013

12,804
46
44
(43)

12,851

614
56
–

670

11,868

12,181

12,190

2014

7,819
3,968
81

$ million

2013

7,812
4,277
92

11,868

12,181

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 Lubricants and Other.

For information on significant estimates and judgements made in relation to impairments see Impairment of property, plant and equipment, intangibles
and goodwill within Note 1.

Upstream

Goodwill
Excess of recoverable amount over carrying amount

2014

7,819
26,077

$ million

2013

7,812
6,811

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

The table above shows the carrying amount of goodwill for the segment and the excess of the recoverable amount over the carrying amount (the
headroom).

In 2014, the recoverable amount is calculated using a fair value less costs of disposal approach, whereas a value-in-use approach was used in 2013.
The change in valuation technique was made in order to more accurately reflect the recoverable amount, based on our view of assumptions that would
be used by a market participant. Both the fair value less costs of disposal and value-in-use calculations are 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 (for value in use) and reserves and risked resources (for fair value less costs of disposal). The fair value calculation is
based primarily on level 3 inputs as defined by the IFRS 13 ‘Fair value measurement’ hierarchy. As the production profile and related cash flows can be
estimated from BP’s experience, management believes that the estimated cash flows expected to be generated over the life of each field is the
appropriate basis upon which to assess goodwill and individual assets for impairment. The estimated 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, 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 management. Capital expenditure,
operating costs and expected hydrocarbon production profiles are derived from the business segment plan adjusted for assumptions reflecting the
current price environment. 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 and resource volumes approved as part of BP’s
centrally controlled process for the estimation of proved and probable reserves and total resources. Intangible assets are deemed to have a recoverable
amount equal to their carrying amount. Consistent with prior years, the 2014 review for impairment was carried out during the fourth quarter.

The key assumptions used in the fair value less costs of disposal calculation are oil and natural gas prices (see Note 1), production volumes and the
discount rate (see Note 1). 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 15% below the current assumption for 2020 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
there is no reasonably possible change in the price assumption for natural gas that would cause the recoverable amount to be equal to the carrying
amount of goodwill and related non-current assets of the segment.

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 847mmboe per year

BP Annual Report and Form 20-F 2014

129

12. Goodwill and impairment review of goodwill – continued

(2013 597mmboe per year). It is estimated that if production volume were to be reduced by approximately 5% 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 post-tax discount rate was approximately 10% 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

Lubricants

Other

2014

Total

Lubricants

3,264

704

3,968

3,518

$ million

2013

Total

4,277

Other

759

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.

Lubricants
As permitted by IAS 36, the detailed calculations of the Lubricants unit’s recoverable amount performed in the most recent detailed calculation in 2013
were used for the 2014 impairment test as the criteria in that standard were considered satisfied: the headroom was substantial in 2013; there have
been no significant changes in the assets and liabilities; and the likelihood that the recoverable amount would be less than the carrying amount at the
time was remote.

The key assumptions to which the calculation of value in use for the Lubricants unit is most sensitive are operating unit margins, sales volumes, and
discount rate. The 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 two-year plan period were extrapolated using a
nominal 3% growth rate.

Exploration
and appraisal
expenditurea

Other
intangibles

Exploration
and appraisal
expenditurea

Other
intangibles

2014

Total

25,678
(175)
455
3,265
(993)
(2,239)

25,991

3,639
(72)
3,333
50
–
(1,866)

5,084

3,936
(175)
455
394
–
(342)

4,268

2,762
(72)
304
50
–
(339)

2,705

24,511
–
–
4,464
(4,365)
(2,868)

21,742

1,077
–
2,710
253
(365)
(2,798)

877

20,865

23,434

21,742
–
–
2,871
(993)
(1,897)

21,723

877
–
3,029
–
–
(1,527)

2,379

19,344

20,865

$ million

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

1,563

20,907

1,174

22,039

1,174

22,039

1,198

24,632

13. Intangible assets

Cost

At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers
Deletions

At 31 December

Amortization

At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Transfers
Deletions

At 31 December

Net book amount at 31 December

Net book amount at 1 January

a For further information see Intangible assets within Note 1 and Note 6.

130

BP Annual Report and Form 20-F 2014

14. Investments in 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

Net assets

Group investment in joint ventures

Group share of net assets (as above)
Loans made by group companies to joint ventures

Transactions between the group and its joint ventures are summarized below.

Sales to joint ventures

Product

LNG, crude oil and oil products, natural gas

Purchases from joint ventures

Sales

3,148

Product

Purchases

LNG, crude oil and oil products, natural gas, refinery operating

$ million

2012

12,507

778
113

665
405

260

(52)

208

2014

2013

12,208

12,507

1,210
125

1,085
515

570

(15)

555

11,586
2,853

14,439

2,222
3,774

5,996

8,443

8,443
310

8,753

1,076
130

946
499

447

485

11,576
3,095

14,671

2,276
3,499

5,775

8,896

8,896
303

9,199

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

2014

Amount
receivable at
31 December

300

2014

Amount
payable at
31 December

2013

Amount
receivable at
31 December

342

2013

Amount
payable at
31 December

Sales

4,125

Purchases

Sales

4,272

Purchases

$ million

2012

Amount
receivable at
31 December

379

$ million

2012

Amount
payable at
31 December

costs, plant processing fees

907

129

503

1,107

116

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.

15. Investments in associates

The following table provides aggregated summarized 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

Income statement

Earnings from associates –
after interest and tax

$ million

Balance sheet

Investments
in associates

2014

2,101
–
701

2,802

2013

2,058
–
684

2,742

2012

–
2,986
689

3,675

2014

7,312
–
3,091

10,403

2013

13,681
–
2,955

16,636

The associate that is material to the group at both 31 December 2014 and 2013 is Rosneft. In 2013, BP sold its 50% interest in TNK-BP to Rosneft and
increased its investment in Rosneft. The net cash inflow in 2013 relating to the transaction included in Net cash used in investing activities in the cash
flow statement was $11.8 billion. From 22 October 2012, the investment in TNK-BP was classified as an asset held for sale and, therefore, equity
accounting ceased. Profits of approximately $738 million and $731 million were not recognized in 2013 and 2012 respectively as a result of the
discontinuance of equity accounting.

BP Annual Report and Form 20-F 2014

131

15. Investments in associates – continued

Since 21 March 2013, BP has owned 19.75% of the voting shares of Rosneft. Rosneft shares are listed on the MICEX stock exchange in Moscow and
its global depositary 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 2014.

BP classifies its investment in Rosneft as an associate because, in management’s judgement, BP has significant influence over Rosneft; see Note 1 –
Interests in other entities – Significant estimate or judgement: accounting for interests in other entities. The group’s investment in Rosneft is a foreign
operation, the functional currency of which is the Russian rouble. The reduction in the group’s equity-accounted investment balance for Rosneft at
31 December 2014 compared with 31 December 2013 was principally due to the weakening of the Russian rouble compared to the US dollar, the
effects of which have been recognized in other comprehensive income.

The fair value of BP’s 19.75% shareholding in Rosneft was $7,346 million at 31 December 2014 (2013 $15,937 million) based on the quoted market
share price of $3.51 per share (2013 $7.62 per share).

The following table provides summarized financial information relating to the group’s material associates. This information is presented on a 100%
basis and reflects adjustments made by BP to the associates’ own results in applying the equity method of accounting. BP adjusts Rosneft’s results for
the accounting required under IFRS relating to BP’s purchase of its interest in Rosneft and the amortization of the deferred gain relating to the disposal
of BP’s interest in TNK-BP. The adjustments relating to Rosneft have increased the reported profit for 2014, as shown in the table below, compared
with the equivalent amount in Russian roubles that we expect Rosneft to report in its own financial statements under IFRS. Consistent with other line
items in the income statement, the amount reported for Rosneft sales and other operating revenue is calculated by translating the amounts reported in
Russian roubles into US dollars using the average exchange rate for the year.

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

Net assets
Less: non-controlling interests

$ million

Gross amount

2014

Rosneft

2013

2012

Rosneft

TNK-BPa

142,856

122,866

49,350

8,810
168

8,642
1,958
712

5,972

5,998

19,367
5,230

14,137
3,428
71

10,638

(13,038)

(2,400)

101,073
38,278

139,351

36,400
65,266

14,106
1,337

12,769
2,137
213

10,419

(441)

9,978

149,149
48,775

197,924

43,175
83,458

101,666

126,633

37,685
663

37,022

71,291
2,020

69,271

a BP ceased equity accounting for TNK-BP on 22 October 2012.

The group received dividends of $693 million from Rosneft in 2014, net of withholding tax (2013 dividends of $456 million from Rosneft and 2012
dividends of $709 million from TNK-BP).

132

BP Annual Report and Form 20-F 2014

15. Investments in associates – continued

Summarized financial information for the group’s share of associates is shown below. 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

28,214

9,724

37,938

24,266

12,998

37,264

24,675

11,965

36,640

Rosnefta

Other

2014

Total

Rosneft

Otherb

2013

Total

TNK-BP

Other

$ million

BP share

2012

Total

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

Net assets
Less: non-controlling interests

Group investment in associates

Group share of net assets (as above)
Loans made by group companies to

associates

3,825
1,033

2,792
677
14

2,101

(2,575)

(474)

19,962
7,560

27,522

7,189
12,890

20,079

7,443
131

7,312

938
7

931
230
–

701

711

2,975
2,199

5,174

1,614
921

2,535

2,639
–

2,639

4,763
1,040

3,723
907
14

2,802

2,786
264

2,522
422
42

2,058

(2,565)

(87)

237

1,971

22,937
9,759

32,696

8,803
13,811

22,614

10,082
131

9,951

29,457
9,633

39,090

8,527
16,483

25,010

14,080
399

13,681

908
11

897
213
–

684

686

3,148
2,477

5,625

2,114
1,053

3,167

2,458
–

2,458

3,694
275

3,419
635
42

2,742

(85)

4,405
84

4,321
979
356

2,986

2,657

2,999

906
16

890
201
–

689

(6)

683

5,311
100

5,211
1,180
356

3,675

3,682

32,605
12,110

44,715

10,641
17,536

28,177

16,538
399

16,139

7,312

2,639

9,951

13,681

2,458

16,139

–

452

–

497

7,312

3,091

10,403

13,681

2,955

16,636

a On 1 October 2014, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars. Since 1 October 2014, foreign exchange gains and

losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments have been recognized initially in other comprehensive
income, and will be reclassified to the income statement as the hedged revenue is recognized over the next five years.

b An amendment has been made to the amount previously disclosed for Sales and other operating revenues.

Transactions between the group and its associates are summarized below.

Sales to associates

Product

LNG, crude oil and oil products, natural gas

Purchases from associates

Product

Crude oil and oil products, natural gas, transportation tariff

2014

Amount
receivable at
31 December

1,258

2014

Amount
payable at
31 December

2013

Amount
receivable at
31 December

783

2013

Amount
payable at
31 December

Sales

5,170

Purchases

Sales

3,771

Purchases

$ million

2012

Amount
receivable at
31 December

401

$ million

2012

Amount
payable at
31 December

2,307

21,205

3,470

9,135

932

Sales

9,589

Purchases

22,703

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.

BP has commitments amounting to $6,946 million (2013 $6,077 million) in relation to contracts with its associates for the purchase of crude oil and oil
products, transportation and storage.

The majority of the sales to, purchases from, and commitments in relation to contracts with associates relate to crude oil and oil products transactions
with Rosneft.

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 2014

133

16. Other investments

Equity investmentsa
Repurchased gas pre-paid bonds
Contingent consideration
Other

a The majority of equity investments are unlisted.

2014

$ million

2013

Current

Non-current

Current

Non-current

–
254
9
66

329

420
153
56
599

1,228

–
276
186
5

467

291
408
292
574

1,565

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 both 31 December 2014 and 2013 the group had contingent consideration receivable, classified as an available-for-sale financial asset, in respect of
the disposal of the Devenick field in 2013.

Other non-current investments at 31 December 2014 of $599 million relate to life insurance policies (2013 $574 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 gains of $41 million were recognized in the income statement (2013 $4 million loss and 2012 $70 million gain).

17. Inventories

Crude oil
Natural gas
Refined petroleum and petrochemical products

Supplies

Trading inventories

2014

5,614
285
8,975

14,874
3,051

17,925
448

18,373

$ million

2013

10,190
235
15,427

25,852
2,735

28,587
644

29,231

Cost of inventories expensed in the income statement

281,907

298,351

The inventory valuation at 31 December 2014 is stated net of a provision of $2,879 million (2013 $322 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 $2,625 million (2013
$195 million charge).

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.

18. 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

a See Note 2 for further information.

Trade and other receivables are predominantly non-interest bearing. See Note 27 for further information.

134

BP Annual Report and Form 20-F 2014

2014

$ million

2013

Current

Non-current

Current

Non-current

19,671
1,558
7,863

29,092

1,154
792

1,946

31,038

166
–
1,293

1,459

2,701
627

3,328

4,787

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

19. Valuation and qualifying accounts

At 1 January
Charged to costs and expenses
Charged to other accountsa
Deductions

At 31 December

a Principally exchange adjustments.

2014

2013

$ million

2012

Accounts
receivable

Fixed asset
investments

Accounts
receivable

Fixed asset
investments

Accounts
receivable

Fixed asset
investments

343
127
(24)
(115)

331

168
438
(2)
(87)

517

489
82
(4)
(224)

343

349
4
4
(189)

168

332
240
7
(90)

489

643
196
18
(508)

349

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.

For information on significant estimates and judgements made in relation to the recoverability of trade receivables see Impairment of loans and
receivables within Note 1.

20. 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 interest free. See Note 27 for further information.

2014

$ million

2013

Current

Non-current

Current

Non-current

23,074
2,436
11,832

37,342

2,776

40,118

–
–
2,985

2,985

602

3,587

28,926
3,576
11,288

43,790

3,369

47,159

21. Provisions

At 1 January 2014
Exchange adjustments
Acquisitions
New or increased provisions
Write-back of unused provisions
Unwinding of discount
Change in discount rate
Utilization
Deletions

At 31 December 2014

Of which – current

– non-current

Of which – Gulf of Mexico oil spillb

Decommissioning Environmentala

Litigation and
claims

Clean Water
Act penalties

17,205
(489)
8
2,216
(60)
202
778
(682)
(458)

18,720

836
17,884

–

3,454
(18)
–
561
(92)
19
21
(1,098)
–

2,847

927
1,920

1,141

4,911
(12)
–
1,290
(27)
12
14
(1,449)
–

4,739

1,420
3,319

3,954

3,510
–
–
–
–
–
–
–
–

3,510

–
3,510

3,510

Other

2,880
(122)
13
1,101
(252)
24
9
(565)
(6)

3,082

635
2,447

–

a Spill response provisions are now included within environmental provisions as they are no longer individually significant.
b Further information on the financial impacts of the Gulf of Mexico oil spill is provided in Note 2.

The decommissioning provision comprises the future cost of decommissioning oil and natural gas wells, facilities and related pipelines. The
environmental provision includes provisions for costs related to the control, abatement, clean-up or elimination of environmental pollution relating to
soil, groundwater, surface water and sediment contamination. The litigation and claims 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 2014 are provisions for deferred employee compensation of $553 million (2013 $602 million).

For information on significant estimates and judgements made in relation to provisions, including those for the Gulf of Mexico oil spill, see Provisions,
contingencies and reimbursement assets within Note 1.

22. 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 benefit 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.

BP Annual Report and Form 20-F 2014

135

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

–
47
4,235

4,282

474

4,756

$ million

Total

31,960
(641)
21
5,168
(431)
257
822
(3,794)
(464)

32,898

3,818
29,080

8,605

22. Pensions and other post-retirement benefits – continued

For information on significant estimates and judgements made in relation to accounting for these plans see Pensions and other post-retirement
benefits within Note 1.

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 corporate trustee whose board is composed of four member-nominated directors, four company-nominated
directors, including an independent director and an independent chairman nominated by the company. 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. 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. Historically this has included a funded final salary pension plan for certain heritage
employees and a cash balance arrangement for new joiners, but with effect from 2015 all employees who are members of the final salary pension plan
accrue benefits only under a cash balance arrangement. 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 BP employees appointed by the president of BP Corporation
North America Inc. (the appointing officer). 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. In the US, group companies also 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.

In the Eurozone, there are defined benefit pension plans in Germany, France, the Netherlands and other countries. In Germany and France, the majority
of the pensions are unfunded, in line with market practice. In Germany, the group’s largest Eurozone plan, employees receive a pension and also have
a choice to supplement their core pension through salary sacrifice. For employees who joined since 2002 the core pension benefit is a career average
plan with retirement benefits based on such factors as employees’ pensionable salary and length of service. The returns on the notional contributions
made by both the company and employees are set out in German tax law. Retired German employees take their pension benefit typically in the form of
an annuity. The German plan is governed by a legal agreement between BP and the works council.

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 2014 the aggregate level of contributions was $1,252 million (2013 $1,272 million and 2012 $1,275 million). The aggregate level of contributions
in 2015 is expected to be approximately $1,250 million, and includes contributions in all countries that we expect to be required to make contributions
by law or under contractual agreements, as well as an allowance for discretionary funding.

For the primary UK plan there is a funding agreement between the group and the trustee. On an annual basis the latest funding position is reviewed
and a schedule of contributions covering the next five years is agreed. The funding agreement can be terminated unilaterally by either party with two
years’ notice. The minimum funding requirement therefore represents seven years of future contributions, which amounted to $4,720 million at 31
December 2014. This amount is included in the group’s committed cash flows relating to pensions and other post-retirement benefit plans as set out in
the table of contractual obligations on page 212. There are no such minimum funding requirements after this seven-year period, and the obligation is
taken into account in the determination of the amount of any pension plan surplus recognized on the balance sheet.

Contributions in the US are determined by legislation and are supplemented by discretionary contributions. All of the contributions made into the US
plan in 2014 were discretionary and no statutory funding requirement is expected in the next 12 months.

There was no minimum funding requirement for the US plan, and no significant minimum funding requirements in other countries at 31 December
2014.

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 2014. 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 and a valuation as at 31 December 2014 is currently under way. A valuation of the US plan is carried out annually.

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 the accrued benefit obligation at 31 December and pension expense for the following
year.

Financial assumptions used to determine benefit obligation

Discount rate for plan liabilities
Rate of increase in salaries
Rate of increase for pensions in payment
Rate of increase in deferred pensions
Inflation for plan liabilities

Financial assumptions used to determine benefit expense

Discount rate for plan service cost
Discount rate for plan other finance expense
Inflation for plan service cost

2014

2013

3.6
4.5
3.0
3.0
3.0

2014

4.8
4.6
3.4

4.6
5.1
3.3
3.3
3.3

2013

4.4
4.4
3.1

UK
2012

4.4
4.9
3.1
3.1
3.1

UK
2012

4.8
4.8
3.2

2014

2013

3.7
4.0
–
–
1.6

2014

4.6
4.3
2.1

4.3
3.9
–
–
2.1

2013

3.3
3.3
2.4

US
2012

3.3
4.2
–
–
2.4

US
2012

4.3
4.3
1.9

2014

2013

2.0
3.4
1.8
0.7
2.0

2014

3.9
3.6
2.0

3.6
3.4
1.8
0.7
2.0

2013

3.5
3.5
2.0

Eurozone
2012

3.5
3.4
1.8
0.7
2.0

Eurozone
2012

4.8
4.8
2.0

The discount rate assumptions are based on third-party AA corporate bond indices and for our largest plans in the UK, US and the Eurozone 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. The Eurozone inflation rate assumption is based on the
central bank inflation target. In other countries we use one of these approaches, or advice from the local actuary depending on the information
available. 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.

136

BP Annual Report and Form 20-F 2014

22. Pensions and other post-retirement benefits – continued

The assumptions for the rate of increase in salaries are based on the inflation assumption plus an allowance for expected long-term real salary growth.
These include allowance for promotion-related salary growth, of up to 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 the Eurozone 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

2014

28.3
30.9
29.4
31.8

2013

27.8
30.7
29.5
32.2

UK
2012

27.7
30.6
29.4
32.1

2014

25.6
27.4
29.1
30.9

2013

24.9
26.4
26.5
27.3

US
2012

24.9
26.3
26.4
27.3

2014

24.7
27.3
28.7
31.1

2013

24.4
26.9
28.5
30.7

Years

Eurozone
2012

24.3
26.9
28.5
30.6

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 of such assets 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 asset allocation policy for the major plans is as follows:

Asset category

Total equity (including private equity)
Bonds/cash
Property/real estate

70
23
7

60
40
–

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 over time, with a view to better matching of the asset portfolio with the pension liabilities. There is a similar agreement in
place in the US.

BP’s principal plans in the UK and US do not currently follow a liability driven investment approach, a form of investing designed to match the
movement in pension plan assets with the movement in projected benefit obligations over time.

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 2014

137

22. 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 139.

Fair value of pension plan assets

At 31 December 2014

Listed equities – developed markets
– emerging markets

Private equity
Government issued nominal bonds
Index-linked bonds
Corporate bonds
Property
Cash
Other

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

UKa

USb

Eurozone

Other

16,190
2,719
2,983
642
892
4,687
2,403
1,145
112

31,773

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

3,026
293
1,571
1,535
–
1,726
7
134
63

8,355

3,260
308
1,432
1,259
–
1,323
6
135
55

7,778

3,622
341
1,468
904
–
1,255
5
87
105

7,787

415
45
2
753
9
541
51
85
72

420
47
26
604
–
340
69
191
38

1,973

1,735

414
32
2
717
12
597
57
120
64

499
52
4
541
57
385
77
158
49

2,015

1,822

307
37
3
532
9
398
54
170
200

537
52
4
510
69
368
85
151
47

1,710

1,823

$ million

Total

20,051
3,104
4,582
3,534
901
7,294
2,530
1,555
285

43,836

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

a Bonds held by the UK pension plans are all denominated in sterling. Property held by the UK pension plans is in the United Kingdom.
b Bonds held by the US pension plans are denominated in US dollars.

138

BP Annual Report and Form 20-F 2014

22. Pensions and other post-retirement benefits – continued

Analysis of the amount charged to profit before interest and taxation
Current service costa
Past service costb
Settlementc
Operating charge relating to defined benefit plans

Payments to defined contribution plans
Total operating charge

Interest income on plan assetsa
Interest on plan liabilities
Other finance expense

Analysis of the amount recognized in other comprehensive income
Actual asset return less interest income on plan assets
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 participantsd
Benefit payments (funded plans)e
Benefit payments (unfunded plans)e
Acquisitions
Disposals
Remeasurements
Benefit obligation at 31 Decembera f

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 g
Contributions by plan participantsd
Contributions by employers (funded plans)
Benefit payments (funded plans)e
Acquisitions
Disposals
Remeasurementsg
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

Eurozone

Other

494
–
–
494

30
524

(1,425)
1,378
(47)

1,269
(3,188)
42
(41)
(1,918)

30,552
(1,993)
494
1,378
39
(1,231)
(10)
–
–
3,187
32,416

31,516
(1,958)
1,425
39
713
(1,231)
–
–
1,269
31,773

356
(33)
(66)
257

214
471

(317)
458
141

768
(1,004)
(264)
13
(487)

11,002
–
257
458
–
(865)
(238)
6
–
1,255
11,875

7,778
–
317
–
354
(865)
3
–
768
8,355

72
20
–
92

11
103

(70)
255
185

119
(1,845)
(20)
(86)
(1,832)

7,536
(1,040)
92
255
4
(83)
(370)
–
(18)
1,951
8,327

2,015
(257)
70
4
110
(83)
–
(5)
119
1,973

87
1
–
88

54
142

(80)
115
35

31
(350)
(9)
(25)
(353)

2,443
(256)
88
115
7
(119)
(24)
–
–
384
2,638

1,822
(161)
80
7
75
(119)
–
–
31
1,735

$ million

2014

Total

1,009
(12)
(66)
931

309
1,240

(1,892)
2,206
314

2,187
(6,387)
(251)
(139)
(4,590)

51,533
(3,289)
931
2,206
50
(2,298)
(642)
6
(18)
6,777
55,256

43,131
(2,376)
1,892
50
1,252
(2,298)
3
(5)
2,187
43,836

(643)

(3,520)

(6,354)

(903)

(11,420)

15
(658)
(643)

(310)
(333)
(643)

–
(3,520)
(3,520)

(19)
(3,501)
(3,520)

3
(6,357)
(6,354)

(663)
(5,691)
(6,354)

13
(916)
(903)

(384)
(519)
(903)

31
(11,451)
(11,420)

(1,376)
(10,044)
(11,420)

(32,083)
(333)
(32,416)

(8,374)
(3,501)
(11,875)

(2,636)
(5,691)
(8,327)

(2,119)
(519)
(2,638)

(45,212)
(10,044)
(55,256)

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of

administering other post-retirement benefit plans are included in the benefit obligation.

b Past service costs in the US include a credit of $21 million as the result of a curtailment in the pension arrangement of a number of employees following a business reorganization and a credit of

$12 million reflecting a plan amendment to a medical plan. A charge of $21 million for special termination benefits represents the increased liability arising as a result of early retirements occurring as
part of restructuring programmes mostly in the Eurozone.

c Settlements represent a gain of $66 million arising from an offer to a group of plan members in the US to settle annuity liabilities with lump sum payments.
d Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
e The benefit payments amount shown above comprises $2,621 million benefits and $257 million settlements, plus $62 million of plan expenses incurred in the administration of the benefit.
f The benefit obligation for the US is made up of $9,033 million for pension liabilities and $2,842 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical

liabilities). The benefit obligation for the Eurozone includes $5,220 million for pension liabilities in Germany which is largely unfunded.

g 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 2014

139

22. 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 assetsa
Interest on plan liabilities
Other finance expense

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
Remeasurementse
Benefit obligation at 31 Decembera f

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
Remeasurementse
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

Eurozone

Other

497
(22)
–
475

24
499

(1,139)
1,223
84

2,671
68
–
43
2,782

29,323
706
475
1,223
37
(1,087)
(5)
(9)
(111)
30,552

27,346
822
1,139
37
597
(1,087)
(9)
2,671
31,516

964

1,291
(327)
964

1,285
(321)
964

407
(49)
–
358

223
581

(240)
406
166

730
1,160
14
(249)
1,655

12,874
–
358
406
–
(1,365)
(285)
(61)
(925)
11,002

7,787
–
240
–
386
(1,365)
–
730
7,778

(3,224)

6
(3,230)
(3,224)

(5)
(3,219)
(3,224)

81
26
–
107

9
116

(63)
254
191

15
62
–
2
79

7,364
323
107
254
4
(87)
(365)
–
(64)
7,536

1,710
92
63
4
218
(87)
–
15
2,015

(5,521)

20
(5,541)
(5,521)

(180)
(5,341)
(5,521)

96
1
(1)
96

44
140

(67)
106
39

99
213
(65)
1
248

2,720
(192)
96
106
9
(105)
(29)
(13)
(149)
2,443

1,823
(129)
67
9
71
(105)
(13)
99
1,822

(621)

59
(680)
(621)

(140)
(481)
(621)

$ 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

(8,402)

1,376
(9,778)
(8,402)

960
(9,362)
(8,402)

(30,231)
(321)
(30,552)

(7,783)
(3,219)
(11,002)

(2,195)
(5,341)
(7,536)

(1,962)
(481)
(2,443)

(42,171)
(9,362)
(51,533)

a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of

administering 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 arrangement 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 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.
f The benefit obligation for the US is made up of $8,364 million for pension liabilities and $2,638 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree medical

liabilities). The benefit obligation for the Eurozone includes $4,874 million for pension liabilities in Germany which is largely unfunded.

140

BP Annual Report and Form 20-F 2014

22. 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

Interest income on plan assetsa
Interest on plan liabilities

Other finance expense

Analysis of the amount recognized in other comprehensive income

Actual asset return less interest income on plan assets
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

Eurozone

Other

477
(1)
–

476

490

(1,146)
1,250

104

379
20
–

399

223

622

(304)
516

212

55
84
4

143

149

(71)
282

211

1,523
(1,476)

718
(1,240)

107
(1,037)

–
(118)

(71)

52
20

(12)
(101)

(450)

(1,043)

96
(2)
(3)

129

(83)
122

66
(26)

(25)
(23)

(8)

$ 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)

a The costs of managing plan investments are offset against the investment return, the costs of administering pension plan benefits are generally included in current service cost and the costs of

administering other post-retirement benefit plans are included in the benefit obligation.

At 31 December 2014, reimbursement balances due from or to other companies in respect of pensions amounted to $426 million reimbursement
assets (2013 $399 million) and $16 million reimbursement liabilities (2013 $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 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 2014 for the group’s plans would have had the effects shown in the table below. The
effects shown for the expense in 2015 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 2015
Effect on pension and other post-retirement benefit obligation at 31 December 2014

Inflation rate

Effect on pension and other post-retirement benefit expense in 2015
Effect on pension and other post-retirement benefit obligation at 31 December 2014

Salary growth

Effect on pension and other post-retirement benefit expense in 2015
Effect on pension and other post-retirement benefit obligation at 31 December 2014

$ million

One percentage point
Decrease

Increase

(499)
(8,174)

487
10,632

543
8,264

157
1,103

(406)
(6,531)

(139)
(1,080)

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 increase the 2015 pension and other post-retirement benefit expense by $74
million and the pension and other post-retirement benefit obligation at 31 December 2014 by $1,582 million.

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 2024 and the weighted
average duration of the defined benefit obligations at 31 December 2014 are as follows:

Estimated future benefit payments

2015
2016
2017
2018
2019
2020-2024

1,192
1,248
1,256
1,329
1,377
7,156

Eurozone

Other

899
917
923
921
916
4,343

439
421
412
400
389
1,848

136
134
139
146
151
791

$ million

Total

2,666
2,720
2,730
2,796
2,833
14,138

years

Weighted average duration

19.0

9.8

14.5

14.2

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23. Cash and cash equivalents

Cash at bank and in hand
Term bank deposits
Cash equivalents

2014

5,112
18,392
6,259

29,763

$ million

2013

6,907
12,246
3,367

22,520

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 2014 includes $2,264 million (2013 $1,626 million) that is restricted. The restricted cash balances include
amounts required to cover initial margin on trading exchanges and certain cash balances which are subject to exchange controls.

The group holds $3 billion (2013 $2 billion) of cash outside the UK and it is not expected that any significant tax will arise on repatriation.

24. Finance debt

Borrowings
Net obligations under finance leases

Current

Non-current

6,831
46

6,877

45,240
737

45,977

2014

Total

52,071
783

52,854

Current

Non-current

7,340
41

7,381

40,317
494

40,811

$ million

2013

Total

47,657
535

48,192

The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of $6,343
million (2013 $6,230 million) and issued commercial paper of $444 million (2013 $1,050 million). Finance debt does not include accrued interest, which
is reported within other payables.

At 31 December 2014, $137 million (2013 $141 million) of finance debt was secured by the pledging of assets. The remainder of finance debt was
unsecured.

The following table shows the weighted average interest rates achieved through a combination of borrowings and derivative financial instruments
entered into to manage interest rate and currency exposures.

US dollar
Other currencies

Fixed rate debt

Floating rate debt

Total

Weighted
average
interest
rate
%

Weighted
average
time for
which rate
is fixed
Years

3
6

3
4

3
19

4
11

Weighted
average
interest
rate
%

1
1

1
2

Amount
$ million

14,285
871

15,156

16,405
611

17,016

Amount
$ million

36,275
1,423

37,698

29,740
1,436

31,176

Amount
$ million

2014

50,560
2,294

52,854

2013

46,145
2,047

48,192

The floating rate debt denominated in other currencies represents euro debt not swapped to US dollars, which is naturally hedged with respect to
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 2014, whereas in the balance
sheet the amount is reported within current finance debt.

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).
Where quoted prices are not available, quoted prices for similar instruments in active markets are used. 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

142

BP Annual Report and Form 20-F 2014

Fair
value

487
51,995
1,343

53,825

2014

Carrying
amount

487
51,584
783

52,854

Fair value

1,110
47,398
654

49,162

$ million

2013

Carrying
amount

1,110
46,547
535

48,192

25. Capital disclosures and analysis of changes in net debt

The group defines capital as total equity. We maintain our financial framework to support the pursuit of value growth for shareholders, while ensuring a
secure financial base. We continue to target a gearing range of 10-20% and to maintain 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 2014, the net debt ratio was 16.7% (2013 16.2%).

At 31 December

Gross debt
Less: fair value asset of hedges related to finance debt

Less: cash and cash equivalents

Net debt

Equity
Net debt ratio

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 activities
Other movements

At 31 December

a Including the fair value of associated derivative financial instruments.

26. Operating leases

2014

52,854
445

52,409
29,763

22,646

$ million

2013

48,192
477

47,715
22,520

25,195

112,642
16.7%

130,407
16.2%

Finance
debta

(47,715)
1,160
(5,419)
–
(435)

(52,409)

Cash and
cash
equivalents

22,520
(671)
7,914
–
–

29,763

2014

Net debt

(25,195)
489
2,495
–
(435)

(22,646)

Finance
debta

(47,100)
(219)
(836)
632
(192)

(47,715)

Cash and
cash
equivalents

19,635
40
2,845
–
–

22,520

$ million

2013

Net debt

(27,465)
(179)
2,009
632
(192)

(25,195)

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The minimum lease payments charged to the income statement in the year were $6,324 million (2013 $5,961 million and 2012 $5,257 million).

The future minimum lease payments at 31 December 2014, before deducting related rental income from operating sub-leases of $234 million (2013
$223 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

2014

5,401
9,916
3,468
18,785

$ million

2013

5,188
10,408
3,590
19,186

In the case of an operating lease entered into by BP as the operator of a joint operation, the amounts included in the totals disclosed 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.

Typical durations of operating leases are up to forty years for leases of land and buildings, up to fifteen years for leases of ships and commercial
vehicles and up to ten years for leases of plant and machinery.

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 2014,
the future minimum lease payments relating to drilling rigs amounted to $8,180 million (2013 $8,776 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.

BP Annual Report and Form 20-F 2014

143

27. 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 2014

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 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

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

16
16

18
28
23

20
28

16
16

18
28
23

20
28

–
–
992
30,551
–
23,504

–
–
–
–

420
538
–
–
–
2,989

–
–
–
–

–
–
–
–
–
3,270

–
–
–
–

55,047

3,947

3,270

–
–
979
39,630
–
19,153

–
–
–
–

291
1,167
–
–
–
2,267

–
–
–
–

–
–
–
–
–
1,100

–
–
–
–

59,762

3,725

1,100

–
599
–
–
8,511
–

–
(6,100)
–
–

3,010

–
574
–
–
5,189
–

–
(4,159)
–
–

1,604

–
–
–
–
1,096
–

–
(788)
–
–

308

–
–
–
–
995
–

–
(388)
–
–

607

–
–
–
–
–
–

(40,327)
–
(7,963)
(52,854)

(101,144)

–
–
–
–
–
–

(48,072)
–
(9,507)
(48,192)

(105,771)

420
1,137
992
30,551
9,607
29,763

(40,327)
(6,888)
(7,963)
(52,854)

(35,562)

291
1,741
979
39,630
6,184
22,520

(48,072)
(4,547)
(9,507)
(48,192)

(38,973)

The fair value of finance debt is shown in Note 24. 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 and interest rates; credit risk; and liquidity risk.

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, credit risk and operational 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 and interest rate risk, each of which is discussed below.

144

BP Annual Report and Form 20-F 2014

27. Financial instruments and financial risk factors – continued

(i) Commodity price risk
The group’s integrated supply and trading function uses conventional financial and commodity instruments and physical cargoes and pipeline positions
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 in liquid periods 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. Trading activity occurring in liquid periods is subject to value-at-risk limits for each trading activity and for this trading
activity in total. The board has delegated a limit of $100 million value at risk in support of this trading activity. Alternative measures are used to monitor
exposures which are outside liquid periods and which cannot be actively risk-managed.

In addition, the group has embedded derivatives relating to certain natural gas contracts. The net fair value of these contracts was a liability of
$214 million at 31 December 2014 (2013 liability of $652 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 28.

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 2014 the most significant open contracts
in place were for $321 million sterling (2013 $723 million sterling).

For other UK, European and Australian operational requirements the group uses cylinders (purchased call and sold put options) to manage the
estimated exposures on a 12-month rolling basis. At 31 December 2014, the open positions relating to cylinders consisted of receive sterling, pay US
dollar cylinders for $2,787 million (2013 $2,770 million); receive euro, pay US dollar cylinders for $867 million (2013 $962 million); receive Australian
dollar, pay US dollar cylinders for $418 million (2013 $401 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 2014, the total foreign
currency net borrowings not swapped into US dollars amounted to $871 million (2013 $665 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 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 2014 was 71% of total finance debt outstanding
(2013 65%). The weighted average interest rate on finance debt at 31 December 2014 was 2% (2013 2%) and the weighted average maturity of fixed
rate debt was four years (2013 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 2015, it is estimated that the group’s finance costs for 2015
would increase by approximately $377 million (2013 $312 million increase).

(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 2014 were $83 million (2013 $199 million) in respect of liabilities of joint ventures and associates and
$244 million (2013 $305 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 is 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.

BP Annual Report and Form 20-F 2014

145

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27. Financial instruments and financial risk factors – continued

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 2014, the group had in place credit enhancements designed to mitigate
approximately $10.8 billion of credit risk (2013 $13 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 2014 it is estimated that over 70% (2013 over 80%)
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 2014, 89% of the cash and cash equivalents balance was deposited with financial institutions rated at least A- by
Standard & Poor’s Rating Services and Fitch Ratings, and A3 by Moody’s Investors Service. Of the total cash and cash equivalents at year end, $8,184
million was held in collateralised tri-partite repurchase agreements. The collateral is held by third-party custodians and would only be released to BP in
the event of repayment default by the borrower.

Trade and other receivables classified as financial assets are analysed in the table below. By comparing the BP credit ratings to the equivalent external
credit ratings, it is estimated that approximately 75-85% (2013 approximately 70-80%) of the unmitigated trade receivables portfolio exposure is of
investment grade credit quality.

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

2014

28,519
37

841
249
178
727

$ million

2013

37,201
27

1,054
249
216
883

30,551

39,630

Movements in the impairment provision for trade receivables are shown in Note 19.

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.

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 2014

Derivative assets
Derivative liabilities
Trade receivables
Trade payables
At 31 December 2013

Derivative assets
Derivative liabilities
Trade receivables
Trade payables

Gross
amounts of
recognized
financial
assets
(liabilities)

11,515
(8,971)
10,502
(9,062)

7,271
(5,457)
11,034
(10,619)

Amounts
set off

(2,383)
2,383
(6,080)
6,080

(1,563)
1,563
(7,744)
7,744

Related amounts not set off
in the balance sheet

Net amounts
presented on
the balance
sheet

Master
netting
arrangements

Cash
collateral
(received)
pledged

9,132
(6,588)
4,422
(2,982)

5,708
(3,894)
3,290
(2,875)

(1,164)
1,164
(485)
485

(344)
344
(1,287)
1,287

(458)
–
(145)
–

(231)
–
(264)
–

$ million

Net amount

7,510
(5,424)
3,792
(2,497)

5,133
(3,550)
1,739
(1,588)

(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.

Standard & Poor’s Rating Services changed BP’s long-term credit rating to A (negative outlook) from A (positive outlook) and Moody’s Investors Service
rating changed to A2 (negative outlook) from A2 (stable outlook) during 2014.

During 2014, $11.8 billion of long-term taxable bonds were issued with terms ranging from 5 to 12 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 $29.8 billion at 31 December
2014 (2013 $22.5 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate and short notice. At
31 December 2014, 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 $7,150 million with a number of banks, allowing LCs to be issued for a maximum
two-year duration. There were also uncommitted secured LC facilities in place at 31 December 2014 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.

146

BP Annual Report and Form 20-F 2014

27. Financial instruments and financial risk factors – continued

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.

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

37,342
708
757
1,446
23
24
27

40,327

Accruals

7,102
493
119
76
41
95
37

7,963

Finance
debt

6,877
6,311
5,652
5,226
6,056
19,504
3,228

52,854

2014

Interest
relating to
finance debt

892
776
672
578
479
1,111
521

5,029

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

$ million

2013

Interest
relating to
finance debt

885
752
621
498
388
809
119

4,072

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 28. 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
settlement amounts (inflows) for the receive leg of derivatives that are settled separately from the pay leg, which amount to $14,615 million at
31 December 2014 (2013 $12,222 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
Over 10 years

2014

293
2,959
2,690
1,505
1,700
5,764
1,325

$ million

2013

1,095
293
2,959
2,577
1,505
3,835
–

16,236

12,264

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28. 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 27. Additionally, the group has a well-established entrepreneurial trading operation that is undertaken in
conjunction with these activities using a similar range of contracts.

For information on significant estimates and judgements made in relation to the application of hedge accounting and the valuation of derivatives see
Derivative financial instruments within Note 1.

The fair values of derivative financial instruments at 31 December are set out below.

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.

BP Annual Report and Form 20-F 2014

147

28. Derivative financial instruments – continued

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
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives

Embedded derivatives

Commodity price contracts

Cash flow hedges

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

122
3,133
3,859
922
389

8,425

1
–

78
1,017

1,095

9,607

5,165
4,442

Fair value
asset

2014

Fair value
liability

Fair value
asset

192
810
2,840
871
475

5,188

129
–

129

340
526

866

(902)
(1,976)
(2,518)
(404)
–

(5,800)

(300)

(161)
(97)

(258)

(518)
(12)

(530)

(6,888)

(3,689)
(3,199)

6,184

2,675
3,509

$ million

2013

Fair value
liability

(111)
(806)
(2,029)
(560)
–

(3,506)

(653)

(30)
(69)

(99)

(154)
(135)

(289)

(4,547)

(2,322)
(2,225)

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 27.

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

Less than
1 year

120
2,434
1,991
488
70

5,103

Less than
1 year

143
694
1,034
528
102
2,501

1-2 years

2-3 years

3-4 years

4-5 years

–
416
644
203
97

1,360

2
185
261
87
161

696

–
63
202
50
61

376

–
31
160
39
–

230

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

$ million

2014

Total

122
3,133
3,859
922
389

8,425

$ million

2013

Total

192
810
2,840
871
475
5,188

Over
5 years

–
4
601
55
–

660

Over
5 years

28
–
600
30
67
725

At both 31 December 2014 and 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.

148

BP Annual Report and Form 20-F 2014

28. Derivative financial instruments – continued

Derivative liabilities held for trading have the following fair values and maturities.

Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives

Less than
1 year

(69)
(1,714)
(1,310)
(217)

(3,310)

Less than
1 year

(111)
(620)
(778)
(400)

(1,909)

1-2 years

2-3 years

3-4 years

4-5 years

(180)
(186)
(292)
(127)

(785)

(1)
(61)
(144)
(39)

(245)

(1)
(8)
(117)
(10)

(136)

(192)
(6)
(99)
(4)

(301)

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)

$ million

2014

Total

(902)
(1,976)
(2,518)
(404)

(5,800)

$ million

2013

Total

(111)
(806)
(2,029)
(560)

(3,506)

Over
5 years

(459)
(1)
(556)
(7)

(1,023)

Over
5 years

–
–
(563)
–

(563)

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

170
6,388
483

7,041
(1,938)

5,103

(37)
(4,905)
(306)

(5,248)
1,938

(3,310)

1,793

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

1-2 years

2-3 years

3-4 years

4-5 years

–
1,353
374

1,727
(367)

1,360

–
(1,017)
(135)

(1,152)
367

(785)

575

–
354
409

763
(67)

696

–
(197)
(115)

(312)
67

(245)

451

–
130
255

385
(9)

376

–
(45)
(100)

(145)
9

(136)

240

–
71
159

230
–

230

–
(202)
(99)

(301)
–

(301)

(71)

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

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$ million

2014

Total

170
8,316
2,322

10,808
(2,383)

8,425

(37)
(6,854)
(1,292)

(8,183)
2,383

(5,800)

2,625

$ 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

Over
5 years

–
20
642

662
(2)

660

–
(488)
(537)

(1,025)
2

(1,023)

(363)

Over
5 years

–
30
695

725
–

725

–
(31)
(532)
(563)
–
(563)
162

BP Annual Report and Form 20-F 2014

149

28. Derivative financial instruments – continued

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.

Net fair value of contracts at 1 January 2014
Gains recognized in the income statement
Settlements
Transfers out of level 3

Net fair value of contracts at 31 December 2014

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

Oil
price

(18)
350
(86)
–

246

Oil
price

105
(47)
110
–
(143)
(43)
–

(18)

Natural gas
price

313
152
(56)
(228)

181

Power
price

86
141
(13)
–

214

Natural gas
price

Power
price

304
62
1
–
(52)
(1)
(1)

313

(43)
81
–
–
10
36
2

$ million

Total

856
737
(335)
(228)

1,030

$ million

Total

437
96
111
475
(256)
(8)
1

856

Other

475
94
(180)
–

389

Other

71
–
–
475
(71)
–
–

475

The amount recognized in the income statement for the year relating to level 3 held for trading derivatives still held at 31 December 2014 was a
$456 million gain (2013 $110 million gain related to derivatives still held at 31 December 2013).

The most significant gross assets and liabilities categorized in level 3 of the fair value hierarchy are US natural gas contracts. At 31 December 2014, the
gross US natural gas price instruments dependent on inputs at level 3 of the fair value hierarchy were an asset of $586 million and liability of $526
million (net fair value of $60 million), with $126 million, net, valued using level 2 inputs. 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. The significant unobservable inputs for fair value measurements
categorized within level 3 of the fair value hierarchy for the year ended 31 December 2014 are presented below.

Natural gas price contracts

Unobservable inputs

Range
$/mmBtu

Weighted average
$/mmBtu

Long-dated market price

3.44-6.39

4.64

If the natural gas prices after 2019 were 10% higher (lower), this would result in a decrease (increase) in derivative assets of $85 million, and decrease
(increase) in derivative liabilities of $64 million, and a net decrease (increase) in profit before tax of $21 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 net gain of
$6,154 million (2013 $587 million net gain and 2012 $411 million net loss). This number does not include gains and losses on realized physical
derivative contracts that have been reflected gross in the income statement within sales and purchases or the change in value of transportation and
storage contracts which are not recognized under IFRS, but does include the associated financially settled contracts. The net amount for actual gains
and losses relating to derivative contracts and all related items therefore differs significantly from the amount disclosed above.

Embedded derivatives
The group is a party to certain natural gas contracts containing embedded derivatives. 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

5 months to 3 years and 9 months
70 million therms

1 year and 5 months to 4 years and 9 months
153 million therms

2014

2013

150

BP Annual Report and Form 20-F 2014

28. Derivative financial instruments – continued

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 historical 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 fair value gain on commodity price embedded derivatives was $430 million (2013 gain of $459 million, 2012 gain of $347 million).

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 recognized in the income statement
Transfers out of level 3
Exchange adjustments

Net fair value of contracts at 31 December

2014

$ million

2013

Commodity
price

(379)
24
219
–
10

(126)

(1,112)
316
142
258
17

(379)

The amount recognized in the income statement for the year relating to level 3 embedded derivatives still held at 31 December 2014 was a
$220 million gain (2013 $67 million gain related to derivatives still held at 31 December 2013).

Cash flow hedges
At 31 December 2014, 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 27 outlines the group’s approach to foreign currency exchange risk management. 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 amounts remaining in equity at 31 December 2014 in relation to these cash flow hedges consist of deferred losses of
$160 million maturing in 2015, deferred losses of $10 million maturing in 2016 and deferred gains of $3 million maturing in 2017 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. 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 2014, 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 loss on the hedging derivative instruments recognized in the income statement in 2014 was $14 million (2013
$1,240 million loss and 2012 $536 million gain) offset by a gain on the fair value of the finance debt of $8 million (2013 $1,228 million gain and 2012
$537 million loss).

The interest rate and cross-currency interest rate swaps mature within one to twelve years, and have the same maturity terms as the debt that they
are hedging. They are used to convert sterling, euro, Swiss franc, Australian dollar, Canadian dollar, Norwegian Krone and Hong Kong dollar
denominated fixed rate borrowings into floating rate debt. Note 27 outlines the group’s approach to interest rate and foreign currency exchange risk
management.

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151

29. 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

20,426,632
165,644
25,598
(611,913)

20,005,961

2014

$ million

12
9

Shares
thousand

7,233
5,473

5,108 20,959,159
202,124
18,203
(752,854)

41
6
(153)

5,002 20,426,632

5,023

2013

$ million

12
9

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

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-based payment plans amounted to $207 million (2013 $116 million and 2012 $47 million).
c Purchased for a total consideration of $4,796 million, including transaction costs of $26 million (2013 $5,493 million, including transaction costs of $30 million). All shares purchased were for

cancellation. The repurchased shares represented 3% 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.

In 2014, the company completed the $8-billion share repurchase programme announced on 22 March 2013 and further continuation of share buybacks
was announced on 29 April 2014. During the year, the company repurchased 612 million ordinary shares at a cost of $4,770 million (2013 753 million
ordinary shares at a cost of $5,463 million). 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 $nil has been accrued at 31 December
2014 (2013 $1,430 million).

Treasury sharesa

At 1 January
Shares re-issued for employee share-based payment plans

At 31 December

a Excluding shares held by ESOPs, see Note 30 for more information.

2014

2013

2012

Shares
thousand

Nominal value
$ million

Shares
thousand

Nominal value
$ million

Shares
thousand

Nominal value
$ million

1,787,939
(16,836)

1,771,103

447
(4)

1,823,408
(35,469)

455
(8)

1,837,508
(14,100)

443

1,787,939

447

1,823,408

459
(4)

455

For each year presented, the balance at 1 January represents the maximum number of shares held in treasury during the year, representing 8.8%
(2013 8.7% and 2012 8.8%) of the called-up ordinary share capital of the company.

During 2014, the movement in treasury shares represented less than 0.1% (2013 less than 0.2% and 2012 less than 0.1%) of the ordinary share capital
of the company.

152

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THIS PAGE INTENTIONALLY LEFT BLANK

BP Annual Report and Form 20-F 2014

153

30. Capital and reserves

At 1 January 2014
Profit for the year
Items that may be reclassified subsequently to profit or loss

Currency translation differences (including recycling)a
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of taxa
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 taxb
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2014

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

At 1 January 2012
Profit for the year
Items that may be reclassified subsequently to profit or loss

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 taxb
Transactions involving non-controlling interests
At 31 December 2012

a Principally affected by a weakening of the Russian rouble compared to the US dollar.
b Includes new share issues and movements in treasury shares where these relate to employee share-based payment plans.

154

BP Annual Report and Form 20-F 2014

Share
premium
account
10,061
–

Capital
redemption
reserve
1,260
–

Total
share capital
and capital
reserves
43,656
–

Merger
reserve
27,206
–

–
–
–
–

–
–
–
(41)
–
240
–
–
10,260

–
–
–
–

–
–
–
–
153
–
–
–
1,413

Share
premium
account
9,974
–

Capital
redemption
reserve
1,072
–

–
–
–
–
–

–
–
–
(51)
–
138
–
–
10,061

–
–
–
–
–

–
–
–
–
188
–
–
–
1,260

Share
premium
account
9,952
–

Capital
redemption
reserve
1,072
–

–
–
–
–
–

–
–
–
(35)
57
–
9,974

–
–
–
–
–

–
–
–
–
–
–
1,072

–
–
–
–

–
–
–
–
–
–
–
–
27,206

Merger
reserve
27,206
–

–
–
–
–
–

–
–
–
–
–
–
–
–
27,206

Merger
reserve
27,206
–

–
–
–
–
–

–
–
–
–
–
–
27,206

–
–
–
–

–
–
–
–
–
246
–
–
43,902

Total
share capital
and capital
reserves
43,513
–

–
–
–
–
–

–
–
–
–
–
143
–
–
43,656

Total
share capital
and capital
reserves
43,454
–

–
–
–
–
–

–
–
–
–
59
–
43,513

Share
capital
5,129
–

–
–
–
–

–
–
–
41
(153)
6
–
–
5,023

Share
capital
5,261
–

–
–
–
–
–

–
–
–
51
(188)
5
–
–
5,129

Share
capital
5,224
–

–
–
–
–
–

–
–
–
35
2
–
5,261

Treasury
shares
(20,971)
–

–
–
–
–

–
–
–
–
–
252
–
–
(20,719)

Treasury
shares
(21,054)
–

–
–
–
–
–

–
–
–
–
–
83
–
–
(20,971)

Treasury
shares
(21,323)
–

–
–
–
–
–

–
–
–
–
269
–
(21,054)

Foreign
currency
translation
reserve
3,525
–

Available-
for-sale
investments
–
–

Cash flow
hedges
(695)
–

Total
fair value
reserves
(695)
–

Profit and
loss
account
103,787
3,780

BP
shareholders’
equity
129,302
3,780

Non-
controlling
interests
1,105
223

(6,934)
–
–
–

–
–
(6,934)
–
–
–
–
–
(3,409)

Foreign
currency
translation
reserve
5,128
–

(1,603)
–
–
–
–

–
–
(1,603)
–
–
–
–
–
3,525

Foreign
currency
translation
reserve
4,509
–

619
–
–
–
–

–
–
619
–
–
–
5,128

1
–
–
–

–
–
1
–
–
–
–
–
1

Available-
for-sale
investments
685
–

–
(685)
–
–
–

–
–
(685)
–
–
–
–
–
–

Available-
for-sale
investments
389
–

–
296
–
–
–

–
–
296
–
–
–
685

–
(203)
–
–

–
–
(203)
–
–
–
–
–
(898)

Cash flow
hedges
1,090
–

–
–
(1,785)
–
–

–
–
(1,785)
–
–
–
–
–
(695)

Cash flow
hedges
(122)
–

(5)
–
1,217
–
–

–
–
1,212
–
–
–
1,090

1
(203)
–
–

–
–
(202)
–
–
–
–
–
(897)

Total
fair value
reserves
1,775
–

–
(685)
(1,785)
–
–

–
–
(2,470)
–
–
–
–
–
(695)

Total fair
value
reserves
267
–

(5)
296
1,217
–
–

–
–
1,508
–
–
–
1,775

–
–
(2,584)
289

(3,256)
4
(1,767)
(5,850)
(3,366)
(313)
73
–
92,564

(6,933)
(203)
(2,584)
289

(3,256)
4
(8,903)
(5,850)
(3,366)
185
73
–
111,441

(32)
–
–
–

–
–
191
(255)
–
–
–
160
1,201

Profit and
loss
account
89,184
23,451

BP
shareholders’
equity
118,546
23,451

Non-
controlling
interests
1,206
307

–
–
–
(24)
(25)

3,243
2
26,647
(5,441)
(6,923)
247
73
–
103,787

(1,603)
(685)
(1,785)
(24)
(25)

3,243
2
22,574
(5,441)
(6,923)
473
73
–
129,302

(15)
–
–
–
–

–
–
292
(469)
–
–
–
76
1,105

Profit and
loss
account
84,661
11,017

BP
shareholders’
equity
111,568
11,017

Non-
controlling
interests
1,017
234

–
–
–
(39)
23

(1,134)
(6)
9,861
(5,294)
(44)
–
89,184

614
296
1,217
(39)
23

(1,134)
(6)
11,988
(5,294)
284
–
118,546

2
–
–
–
–

2
–
238
(82)
–
33
1,206

$ million

Total
equity
130,407
4,003

(6,965)
(203)
(2,584)
289

(3,256)
4
(8,712)
(6,105)
(3,366)
185
73
160
112,642

Total
equity
119,752
23,758

(1,618)
(685)
(1,785)
(24)
(25)

3,243
2
22,866
(5,910)
(6,923)
473
73
76
130,407

Total
equity
112,585
11,251

616
296
1,217
(39)
23

(1,132)
(6)
12,226
(5,376)
284
33
119,752

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BP Annual Report and Form 20-F 2014

155

30. 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.

Treasury shares
Treasury shares represent BP shares repurchased and available for specific and limited purposes.

For accounting purposes shares held in Employee Share Ownership Plans (ESOPs) to meet the future requirements of the employee share-based
payment plans are treated in the same manner as treasury shares and are therefore included in the financial statements as treasury shares. The ESOPs
are funded by the group and have waived their rights to dividends in respect of such shares held for future awards. Until such time as the 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 2014, the ESOPs held 34,169,554 shares (2013 32,748,354 shares and 2012 22,428,179 shares) for potential future awards, which
had a market value of $219 million (2013 $253 million and 2012 $154 million). At 31 December 2014, a further 6,024,978 ordinary share equivalents
(2013 12,856,914 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.

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 – Derivative financial instruments and hedging activities.

Profit and loss account
The balance held on this reserve is the accumulated retained profits of the group.

156

BP Annual Report and Form 20-F 2014

30. 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)
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

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

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

31. Contingent liabilities

$ million

2014

Pre-tax

Tax

Net of tax

(6,787)
(239)
(2,584)
–

(4,590)
4
(14,196)

(178)
36
–
289

1,334
–
1,481

(6,965)
(203)
(2,584)
289

(3,256)
4
(12,715)

$ 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

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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 2014 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 27.

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.

BP Annual Report and Form 20-F 2014

157

31. Contingent liabilities – continued

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.

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 it is possible that, in certain circumstances, BP could be partially or wholly responsible for decommissioning. Furthermore, as described in
Provisions, contingencies and reimbursement assets within Note 1, decommissioning provisions associated with downstream and petrochemical
facilities are not generally recognized as the potential obligations cannot be measured given their indeterminate settlement dates.

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.

32. Remuneration of senior management and non-executive directors

Remuneration of directors

Total for all directors

Emoluments
Amounts awarded under incentive schemes

Total

2014

2013

14
14

16
2

$ million

2012

12
3

Emoluments
These amounts comprise fees 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 2014 (2013 $nil and
2012 $nil).

Pension contributions
During 2014 two executive directors participated in a non-contributory pension scheme established for UK employees by a separate trust fund to which
contributions are made by BP based on actuarial advice. One US executive director participated in the US BP Retirement Accumulation Plan during
2014.

Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 72.

Remuneration of senior management and non-executive directors

Total for senior management and non-executive directors

Short-term employee benefits
Pensions and other post-retirement benefits
Share-based payments

Total

2014

2013

34
3
34

36
3
43

$ million

2012

29
3
37

Senior management, comprises members of the executive team, see pages 56-57 for further information.

Short-term employee benefits
These amounts comprise fees and benefits paid to the non-executive chairman and non-executive directors, as well as salary, benefits and cash
bonuses for senior management. 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 $1.5 million (2013 $3 million and 2012 $nil).

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’.

158

BP Annual Report and Form 20-F 2014

33. Employee costs and numbers

Employee costs

Wages and salariesa
Social security costs
Share-based paymentsb
Pension and other post-retirement benefit costs

2014

10,710
983
689
1,554

13,936

2013

10,161
958
719
1,816

13,654

Average number of employeesc

Upstream
Downstreamd
Other businesses and corporatee f

Non-US

9,100
8,200
1,800

19,100

15,600
39,900
10,100

65,600

2014

Total

24,700
48,100
11,900

84,700

Non-US

9,400
9,300
2,000

20,700

15,100
39,800
9,000

63,900

2013

Total

24,500
49,100
11,000

84,600

Non-US

9,300
12,000
2,000

23,300

14,100
39,900
8,700

62,700

a Includes termination payments of $527 million (2013 $212 million and 2012 $77 million).
b 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.
c Reported to the nearest 100.
d Includes 14,200 (2013 14,100 and 2012 14,700) service station staff.
e Includes 5,100 (2013 4,300 and 2012 3,600) agricultural, operational and seasonal workers in Brazil.
f Includes employees of the Gulf Coast Restoration Organization.

$ million

2012

9,910
908
674
1,956

13,448

2012

Total

23,400
51,900
10,700

86,000

34. Auditor’s remuneration

Fees – Ernst & Young

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

2014

2013

$ million

2012

27
13

40
7

1
1
1
2

26
13

39
8

1
1
2
1

F
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26
13

39
7

2
2
2
1

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 $398,000 (2013 $240,000 and 2012 $50,000).

2014 includes $2 million of additional fees for 2013, and 2013 includes $3 million of additional fees for 2012. 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 (2013 $53 million and 2012 $54 million) is required to be presented as follows:
audit $40 million (2013 $39 million and 2012 $39 million); other audit-related services $7 million (2013 $8 million and 2012 $7 million); tax $2 million
(2013 $2 million and 2012 $4 million); and all other fees $4 million (2013 $4 million and 2012 $4 million).

BP Annual Report and Form 20-F 2014

159

35. Subsidiaries, joint arrangements and associates

The more important subsidiaries and associates of the group at 31 December 2014 and the group percentage of ordinary share capital (to nearest
whole number) are set out below. There are no individually significant joint arrangements. Those held directly by the parent company are marked with
an asterisk (*), the percentage owned being that of the group unless otherwise indicated. 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

Germany

BP Europa SE

India

BP Exploration (Alpha)

Norway

BP Norge

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

Germany

Refining and marketing

100

England & Wales

Exploration and production

100

Norway

Exploration and production

100

England & Wales

Finance

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

Russia

Integrated oil operations

160

BP Annual Report and Form 20-F 2014

36. 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

Equity-accounted other comprehensive income of subsidiaries

Total comprehensive income

Attributable to

BP shareholders
Non-controlling interests

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

BP p.l.c.

Other
subsidiaries

Eliminations and
reclassifications

6,227
–
–
–
2
19

6,248
2,375
1,779
554
545
153
–
48
–

794
57

–

737
279

458

458
–

458

–
–
–
4,531
193
–

4,724
–
–
–
–
–
–
929
–

3,795
23

(50)

3,822
42

3,780

3,780
–

3,780

353,529
570
2,802
–
910
876

358,687
285,720
25,596
2,404
14,618
8,812
3,632
11,794
(430)

6,541
1,255

364

4,922
626

4,296

4,073
223

4,296

(6,188)
–
–
(4,531)
(262)
–

(10,981)
(6,188)
–
–
–
–
–
(75)
–

(4,718)
(187)

–

(4,531)
–

(4,531)

(4,531)
–

(4,531)

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

$ million

2014

BP group

353,568
570
2,802
–
843
895

358,678
281,907
27,375
2,958
15,163
8,965
3,632
12,696
(430)

6,412
1,148

314

4,950
947

4,003

3,780
223

4,003

$ million

2014

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

458

–

458

458
–
458

BP p.l.c.

3,780

Other
subsidiaries

Eliminations and
reclassifications

4,296

(4,531)

BP group

4,003

(1,840)

(10,875)

–

(12,715)

(10,843)

(8,903)

(8,903)
–
(8,903)

–

(6,579)

(6,770)
191
(6,579)

10,843

6,312

6,312
–
6,312

–

(8,712)

(8,903)
191
(8,712)

BP Annual Report and Form 20-F 2014

161

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

23,453
2

23,451

23,451
–

23,451

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)

$ 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

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

840

–

BP p.l.c.

23,451

2,819

(3,696)

Other
subsidiaries

Eliminations and
reclassifications

24,160

(3,711)

–

(24,693)

–

3,696

BP group

23,758

(892)

–

840

22,574

20,449

(20,997)

22,866

840
–

840

22,574
–

22,574

20,157
292

20,449

(20,997)
–

(20,997)

22,574
292

22,866

36. Condensed consolidating information on certain US subsidiaries – continued

Income statement continued

For the year ended 31 December

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

Equity-accounted other comprehensive income of subsidiaries

Total comprehensive income

Attributable to

BP shareholders
Non-controlling interests

162

BP Annual Report and Form 20-F 2014

36. Condensed consolidating information on certain US subsidiaries – continued

Income statement continued

For the year ended 31 December

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

Equity-accounted other comprehensive income of subsidiaries

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

–

3,708

3,708
–

3,708

BP p.l.c.

11,017

(232)

1,203

11,988

11,988
–

11,988

$ 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

–

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

12,696

1,207

–

(16,170)

–

(1,203)

13,903

(17,373)

12,226

13,665
238

13,903

(17,373)
–

(17,373)

11,988
238

12,226

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 2014

163

36. 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

Total assets

Current liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions

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

164

BP Annual Report and Form 20-F 2014

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

BP p.l.c.

Other
subsidiaries

Eliminations and
reclassifications

$ million

2014

BP group

130,692
11,868
20,907
8,753
10,403
1,228
–

183,851
659
4,787
4,442
964
2,309
31

–
–
–
–
–
–
(138,863)

(138,863)
(4,586)
–
–
–
–
–

(143,449)

197,043

–
–
(19,907)
–
–
–
–
–

(19,907)

333
18,373
31,038
5,165
1,424
837
329
29,763

87,262

–
–
–
–
2
–
138,863

138,865
–
–
–
–
–
15

138,880

–
–
7,159
–
–
–
–
31

7,190

122,905
11,868
20,434
8,753
10,401
1,228
–

175,589
5,238
4,787
4,442
954
2,309
16

193,335

333
18,035
33,463
5,165
1,393
837
329
29,732

89,287

146,070

282,622

(163,356)

284,305

2,476
–
391
–
–
–

2,867

4,563
–
90
–
–
–

599

5,252

8,119

56,644
3,689
6,577
6,877
1,683
3,817

79,287

3,594
3,199
771
45,977
12,661
27,105

10,852

104,159

183,446

99,176

97,975
1,201

99,176

(19,907)
–
–
–
–
–

(19,907)

(4,586)
–
–
–
–
–

40,118
3,689
7,102
6,877
2,011
3,818

63,615

3,587
3,199
861
45,977
13,893
29,080

–

11,451

(4,586)

108,048

(24,493)

171,663

(138,863)

112,642

(138,863)
–

111,441
1,201

(138,863)

112,642

14,378

137,951

14,378
–

14,378

137,951
–

137,951

7,787
–
473
–
–
–
–

8,260
7
–
–
10
–
–

8,277

–
338
10,323
–
31
–
–
–

10,692

18,969

905
–
134
–
328
1

1,368

16
–
–
–
1,232
1,975

–

3,223

4,591

36. 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

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

99,196

(33,675)

96,840

18,748

164,721

302,632

(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)
–
–
–
–
–
–

(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

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 2014

165

36. 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 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 (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

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

92
(92)
–
–

–
–

–

BP p.l.c.

15,550
(5,085)
(10,440)
–

25
6

Other
subsidiaries

Eliminations and
reclassifications

19,241
(14,397)
3,045
(671)

7,218
22,514

29,732

(2,129)
–
2,129
–

–
–

–

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

746
(746)
–
–

–
–

–

BP p.l.c.

11,488
(690)
(10,801)
–

(3)
9

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

681
(680)
–
–

1
(1)

–

BP p.l.c.

12,381
(7,060)
(5,312)
–

9
–

Other
subsidiaries

Eliminations and
reclassifications

25,094
(6,419)
(15,827)
40

2,888
19,626

22,514

(16,228)
–
16,228
–

–
–

–

Other
subsidiaries

Eliminations and
reclassifications

20,932
(5,335)
(10,213)
64

5,448
14,178

19,626

(13,515)
–
13,515
–

–
–

–

$ million

2014

BP group

32,754
(19,574)
(5,266)
(671)

7,243
22,520

29,763

$ 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

166

BP Annual Report and Form 20-F 2014

Supplementary information on oil and natural gas (unaudited)a
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 pages 219–224.

a 2013 equity-accounted entities information includes BP’s share of TNK-BP from 1 January to 20 March, and Rosneft for the period 21 March to 31 December.

F
i
n
a
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c
i
a
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s
t
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BP Annual Report and Form 20-F 2014

167

Oil and natural gas exploration and production activities

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2014

Total

Subsidiariesa
Capitalized costs at 31 Decemberb

Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation

Net capitalized costs

31,496
395

31,891
21,068

10,823

10,578
165

10,743
6,610

76,476
6,294

82,770
39,383

4,133

43,387

3,205
2,454

5,659
190

5,469

9,796
2,984

12,780
5,482

39,020
5,769

44,789
25,105

7,298

19,684

Costs incurred for the year ended 31 Decemberb

Acquisition of properties

Proved
Unproved

Exploration and appraisal costsc
Development

Total costs

42
–

42
279
2,067

2,388

–
–

–
16
293

309

6
346

352
888
4,792

6,032

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

529
1,069

1,598

94
979
(234)
(1,515)
506

2,537

2,367

(769)
(1,383)

614

77
1,662

1,739

47
436
–
77
676

1,218
14,894

16,112

1,294
3,492
690
3,260
3,805

2,278

3,514

(1,775)
(1,108)

(667)

(28)

12,513

3,599
1,269

2,330

–
–

–
109
706

815

4
15

63
34
–
55
4

–

156

(137)
15

(152)

–
75

75
325
983

1,383

2,802
450

3,252

502
783
175
284
678

2,433

819
865

(46)

–
57

57
899
2,881

3,837

2,536
6,289

8,825

860
1,542
–
120
3,343

1,128

6,993

1,832
1,216

616

Upstream and Rosneft segments replacement cost profit before interest and tax

–
–

–

–
–

–

–
–

–

–
–
–
57
–

–

(57)
3

(60)

24,177
2,773

26,950
13,501

13,449

5,061
888

5,949
2,215

3,734

199,809
21,722

221,531
113,554

107,977

557
–

557
194
3,205

3,956

1,135
6,951

8,086

712
1,289
2,234
(69)
2,461

391

7,018

1,068
67

1,001

–
–

–
201
169

370

1,891
631

2,522

60
232
93
306
255

605
478

1,083
2,911
15,096

19,090

10,192
31,961

42,153

3,632
8,787
2,958
2,575
11,728

–

6,317

946

35,997

1,576
599

977

6,156
1,543

4,613

Exploration and production activities –

subsidiaries (as above)

Midstream activities – subsidiariesg
Equity-accounted entitiesh

Total replacement cost profit before

(769)
163
–

(1,775)
99
62

3,599
703
23

(137)
130
–

819
175
480

1,832
(170)

(57)
(26)
(33) 2,125

1,068
(63)
557

1,576
653
–

6,156
1,664
3,214

interest and tax

(606)

(1,614)

4,325

(7)

1,474

1,629

2,042

1,562

2,229

11,034

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 $430 million. The UK region includes a $1,016 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 $207 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.

168

BP Annual Report and Form 20-F 2014

Oil and natural gas exploration and production activities – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
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 Decemberd
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 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

–
–
–
–
–
–
–

–

–
–
–
–
–

–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

8,719
5
8,724
3,652
5,072

–
–
–
5
1,026
1,031

2,472
–
2,472
4
567
721
4

370

25
1,691
781
402
379

379

101

480

Russiaa

Rest of
Asia

12,971
376
13,347
2,031
11,316

3,073
25
3,098
2,986
112

(46)
87
41
128
1,913
2,082

–
–
–
4
669
673

–
10,972
10,972
62
1,318
5,214
302

1,257
19
1,276
1
152
692
–

1,509

371

–
8,405
2,567
637
1,930

–
1,216
60
29
31

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

1,930

(33)

195

526

(33)

2,125

557

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

$ million

2014

Total

24,763
406
25,169
8,669
16,500

(46)
87
41
137
3,608
3,786

3,729
10,991
14,720
67
2,037
6,627
306

2,250

25
11,312
3,408
1,068
2,340

2,340

874

3,214

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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 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 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 interests and excludes inventory holding gains and losses.

BP Annual Report and Form 20-F 2014

169

Oil and natural gas exploration and production activities – continued

Europe

Rest of
Europe

North
America

Rest of
North
America

South
America

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

(80)

1,038

11,669

425
475

(50)

3,312
1,204

2,108

–
–

–
194
569

763

5
12

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)

5,260

4,453
1,925

2,528

Upstream, Rosneft and TNK-BP segments replacement cost profit before interest and tax

Africa

Asia

Australasia

$ million

2013

Total

Russia

Rest of
Asia

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
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

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

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.

170

BP Annual Report and Form 20-F 2014

Oil and natural gas exploration and production activities – continued

Europe

Rest of
Europe

North
America

Rest of
North
America

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 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

–
–
–
–
–
–
–

–

–
–
–
–
–

–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

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

Africa

Asia

Australasia

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

$ 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

–
–
–
–
–

–
–
–
–
–
–

–
–
–
–
–
–
–

–

–
–
–
–
–

–

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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 interests and excludes inventory holding gains and losses.

BP Annual Report and Form 20-F 2014

171

Africa

Asia

Australasia

$ million

2012

Total

Oil and natural gas exploration and production activities – continued

Europe

Rest of
Europe

North
America

Rest of
North
America

South
America

Subsidiariesa
Capitalized costs at 31 Decemberb c

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 propertiesd e

Proved
Unproved

Exploration and appraisal costsf
Development

Total costs

–
–

–
173
1,907

2,080

Results of operations for the year ended 31 December

Sales and other operating revenuesg

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)h
Depreciation, depletion and

amortization

Impairments and (gains) losses on sale

of businesses and fixed assets

Profit (loss) before taxationi
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

4
71
–
63

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

683

176
(313)

489

(3,576)

9,091

7,075
2,762

4,313

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

1,815

1,195
804

391

4,159

4,898
2,371

2,527

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

Upstream and TNK-BP segments replacement cost profit before interest and tax
Exploration and production activities –

subsidiaries (as above)

Midstream activities – subsidiariesj
Equity-accounted entitiesk

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

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 Excludes balances associated with assets held for sale.
d Includes costs capitalized as a result of asset exchanges.
e Excludes goodwill associated with business combinations.
f 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.
g Presented net of transportation costs, purchases and sales taxes.
h 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.

i 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.
j Midstream and other activities exclude inventory holding gains and losses.
k The profits of equity-accounted entities are included after interest and tax and the results exclude balances associated with assets held for sale.

172

BP Annual Report and Form 20-F 2014

Oil and natural gas exploration and production activities – continued

Europe

Rest of
Europe

North
America

Rest of
North
America

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

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

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

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

$ 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

916

3,904

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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. Capitalised 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 interests and the net results of equity-accounted entities and excludes inventory holding gains and losses.

BP Annual Report and Form 20-F 2014

173

Movements in estimated net proved reserves

Crude oila b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place

At 31 Decembere
Developed
Undeveloped

Equity-accounted entities (BP share)f
At 1 January
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 Decemberg
Developed
Undeveloped

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

160
374

At 31 December
Developed
Undeveloped

534

159
329

488

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

USc

Russia

Rest of
Asia

million barrels

2014

Total

160
374

534

(41)
2
5
5
(17)
–

(46)

159
329

488

–
–

–

–
–
–
–
–
–

–

–
–

–

147
53

200

(68)
–
–
–
(15)
–

(82)

95
22

117

1,007
752

1,760

87
16
–
–
(123)
(45)

(66)

1,030
664

1,694

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

147
53

200

95
22

117

1,007
752

1,760

1,030
664

1,694

–
–

–

–
–
–
–
–
–

–

–
–

–

–
1

–
–
–
–
–
–

–

–
–

–
1

–
–

15
17

9
1
–
1
(5)
(5)

10
22

316
314

630

4
12
–
10
(26)
–

–

316
314

630

331
331

661

326
336

662

316
180

495

20
3
–
–
(81)
–

(58)

317
120

437

2
2

(2)
–
–
–
–
–

(2)

2
–

317
182

499

319
120

439

–
–

–

–
–
–
–
–
–

–

–
–

–

2,970
1,858

4,828

213
–
–
187
(297)
–

103

2,997
1,933

4,930

2,970
1,858

4,828

2,997
1,933

4,930

320
202

522

96
–
12
8
(57)
–

384
197

581

120
7

127

9
–
–
–
(36)
–

(27)

89
11

101

440
209

649

473
208

682

49
19

(2)
–
–
–
(7)
–

(9)

40
19

–
–

–

–
–
–
–
–
–

–

–
–

–

49
19

40
19

2,013
1,597

3,610

101
23
17
13
(305)
(50)

(201)

2,035
1,375

3,409

3,407
2,182

5,590

224
12
–
197
(359)
–

3,405
2,258

5,663

5,421
3,779

9,200

5,440
3,632

9,072

a Crude oil includes 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 Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 65 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.

d Includes 10 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 38 million barrels of crude oil in respect of the 0.15% non-controlling interest in Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,961 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 30 million barrels in Venezuela and

4,930 million barrels in Russia.

174

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Natural gas liquidsa b

Subsidiaries
At 1 January
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 Decemberd
Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January
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 Decemberf
Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

million barrels

2014

Total

9
6

(6)
–
–
–
(1)
–

(6)

6
3

–
–

–

–
–
–
–
–
–

–

–
–

–

Rest of
Europe

16
2

(2)
–
–
–
(2)
–

(4)

13
1

–
–

–

–
–
–
–
–
–

–

–
–

–

16
2

13
1

Rest of
North
America

Russia

Rest of
Asia

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

14
28

–
–
–
–
(4)
–

(4)

11
28

–
–

–

–
–
–
–
–
–

–

–
–

–

14
28

11
28

4
15

(6)
–
–
–
(2)
–

(8)

5
7

8
8

–
–
–
–
–
–

(1)

15
–

13
23

20
7

–
–

–

–
–
–
–
–
–

–

–
–

–

94
21

115

(69)
–
–
–
–
–

(69)

30
16

94
21

115

30
16

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

290
155

444

15
13
–
–
(27)
(18)

(17)

323
104

427

–
–

–

–
–
–
–
–
–

–

–
–

–

290
155

444

323
104

427

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

8
3

–
–
–
–
(1)
–

(1)

6
3

–
–

–

–
–
–
–
–
–

–

–
–

–

8
3

6
3

342
209

551

1
13
1
–
(36)
(18)

(40)

364
146

510

103
29

131

(69)
–
–
–
–
–

(69)

46
16

444
238

682

410
163

572

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

9
6

At 31 December
Developed
Undeveloped

6
3

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 7 thousand barrels per day for equity-accounted entities.
d Includes 12 million barrels of NGL 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 Total proved NGL reserves held as part of our equity interest in Rosneft is 47 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 46 million barrels in Russia.

BP Annual Report and Form 20-F 2014

175

Movements in estimated net proved reserves – continued

Bitumena b

Subsidiaries

At 1 January
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
Developed
Undeveloped

million barrels

2014

Total

–
188

188

(16)
–
–
–
–
–

(16)

9
163

172

Rest of
North
America

–
188

188

(16)
–
–
–
–
–

(16)

9
163

172

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.

176

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Total liquidsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place

At 31 Decembere
Developed
Undeveloped

Equity-accounted entities (BP share)f
At 1 January
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 Decemberg h

Developed
Undeveloped

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

169
380

At 31 December
Developed
Undeveloped

549

166
332

497

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

USc

Russia

Rest of
Asia

million barrels

2014

Total

169
380

549

(47)
2
5
5
(17)
–

(52)

166
332

497

–
–

–

–
–
–
–
–
–

–

–
–

–

163
55

217

(70)
–
–
–
(17)
–

(86)

108
23

131

1,297
907

2,204

101
28
–
–
(150)
(63)

(83)

1,352
769

2,121

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
188

188

(16)
–
–
–
–
–

(16)

9
163

172

–
1

–
–
–
–
–
–

–

–
–

163
55

217

108
23

131

1,297
907

2,204

1,352
769

2,121

–
188

189

9
164

173

29
46

9
1
–
1
(9)
(5)

(3)

21
50

316
314

630

4
12
–
10
(26)
–

–

316
314

630

345
359

704

337
364

701

320
195

515

14
3
–
–
(83)
–

(66)

322
127

449

10
10

(3)
–
–
–
–
–

(3)

17
–

331
205

535

339
127

466

–
–

–

–
–
–
–
–
–

–

–
–

–

3,063
1,879

4,943

144
–
–
187
(297)
–

3,028
1,949

4,976

3,063
1,879

4,943

3,028
1,949

4,976

320
202

523

96
–
12
8
(57)
–

384
197

581

120
7

127

9
–
–
–
(36)
–

(27)

89
11

101

440
209

650

473
208

682

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

57
22

(2)
–
–
–
(8)
–

(10)

46
22

–
–

–

–
–
–
–
–
–

–

–
–

–

57
22

46
22

2,354
1,994

4,348

86
36
18
14
(341)
(68)

(257)

2,407
1,684

4,092

3,510
2,210

5,721

155
12
–
197
(359)
–

3,451
2,274

5,725

5,865
4,204

10,069

5,858
3,958

9,817

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 65 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 less than 1 thousand barrels per day for subsidiaries and 7 thousand barrels per day for equity-accounted entities.
e Also includes 21 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 38 million barrels in respect of the non-controlling interest in Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,007 million barrels, comprising 1 million barrels in Canada, 30 million barrels in Venezuela, less than 1 million barrels in

Vietnam and 4,976 million barrels in Russia.

BP Annual Report and Form 20-F 2014

177

Movements in estimated net proved reserves – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

billion cubic feet

2014

Total

Natural gasa b

Subsidiaries
At 1 January
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 Decemberd
Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January
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 Decemberf g

Developed
Undeveloped

3,109
6,116

9,225

961
1,807

2,768

(258)
220
–
271
(792)
–

(559)

(84)
28
–
4
(218)
–

(271)

2,352
6,313

8,666

901
1,597

2,497

–
–

–

–
–
–
–
–
–

–

–
–

–

1,364
747

2,111

230
135

365

4,171
5,054

9,225

(87)
23
–
69
(172)
–

(166)

38
–
–
–
(3)
–

767
–
–
183
(390)
–

560

1,228
717

1,945

400
–

400

4,674
5,111

9,785

1,519
3,671

5,190

(34)
–
322
267
(165)
–

389

1,688
3,892

5,580

72
14

1
–
–
–
(18)
–

(17)

60
9

643
314

957

(260)
7
1
94
(30)
–

(189)

382
386

768

–
–

–

–
–
–
–
–
–

–

–
–

–

364
39

403

(46)
–
–
–
(40)
–

(85)

300
19

318

7,122
2,825

9,947

(29)
582
5
2
(625)
(266)

(332)

7,168
2,447

9,615

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

364
39

403

300
19

318

7,122
2,825

9,947

7,168
2,447

9,615

10
–

11
–
–
–
(4)
–

17
–

–
1

1
–
–
–
–
–

–

1
1

10
1

18
1

3,932
1,755

5,687

17,660
16,527

34,187

(351)
–
–
–
(302)
–

(652)

(1,050)
838
328
637
(2,177)
(266)

(1,691)

3,316
1,719

5,035

16,124
16,372

32,496

–
–

–

–
–
–
–
–
–

–

–
–

–

5,837
5,951

11,788

720
23
–
252
(583)
–

412

6,363
5,837

12,200

23,497
22,478

45,975

22,487
22,209

44,695

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

643
314

At 31 December
Developed
Undeveloped

957

382
386

768

4,473
6,863

11,336

3,581
7,030

10,610

1,191
1,942

3,133

1,301
1,597

2,897

4,171
5,054

9,225

4,674
5,111

9,785

1,591
3,685

5,276

1,748
3,901

5,648

3,932
1,755

5,687

3,316
1,719

5,035

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c Includes 181 billion cubic feet of natural gas consumed in operations, 151 billion cubic feet in subsidiaries, 29 billion cubic feet in equity-accounted entities.
d Includes 2,519 billion cubic feet of natural gas 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 91 billion cubic feet of natural gas in respect of the 0.18% non-controlling interest in Rosneft.
g Total proved gas reserves held as part of our equity interest in Rosneft is 9,827 billion cubic feet, comprising 1 billion cubic feet in Canada, 14 billion cubic feet in Venezuela, 26 billion cubic feet in

Vietnam and 9,785 billion cubic feet in Russia.

178

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

USd

Russia

Rest of
Asia

2014

Total

million barrels of oil equivalentc

Total hydrocarbonsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place

At 31 Decemberg
Developed
Undeveloped

Equity-accounted entities (BP share)h
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionf
Sales of reserves-in-place

At 31 Decemberi j

Developed
Undeveloped

280
434

714

(91)
3
6
21
(23)
–

(84)

232
398

630

–
–

–

–
–
–
–
–
–

–

–
–

–

225
62

287

(78)
–
–
–
(24)
–

(101)

160
26

186

2,525
1,394

3,919

96
129
1
1
(258)
(109)

(140)

2,588
1,191

3,779

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

2
188

190

(14)
–
–
–
(1)
–

(14)

12
163

175

–
1

–
–
–
–
–
–

–

–
1

564
1,100

1,664

(36)
39
–
47
(146)
(5)

(99)

426
1,139

1,565

552
442

994

(11)
16
–
22
(56)
–

(29)

528
438

965

486
507

993

(1)
8
–
1
(121)
–

(113)

477
403

880

50
33

4
–
–
–
(1)
–

86
–

–
–

–

–
–
–
–
–
–

–

–
–

–

3,782
2,751

6,533

276
–
–
219
(365)
–

130

3,834
2,830

6,663

3,782
2,751

6,533

3,834
2,830

6,663

582
835

1,417

90
–
68
54
(86)
–

126

675
868

1,543

133
9

142

9
–
–
–
(39)
–

(29)

100
13

112

715
844

1,559

775
881

1,656

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

735
324

5,399
4,844

1,059

10,243

(62)
–
–
–
(60)
–

(122)

618
319

937

–
–

–

–
–
–
–
–
–

–

–
–

–

(96)
180
74
123
(717)
(114)

(548)

5,187
4,507

9,694

4,517
3,236

7,753

278
16
–
241
(460)
–

4,548
3,280

7,828

735
324

9,916
8,080

1,059

17,996

618
319

937

9,735
7,788

17,523

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

280
434

At 31 December
Developed
Undeveloped

714

232
398

630

225
62

287

160
26

186

2,525
1,394

3,919

2,588
1,191

3,779

2
189

191

12
164

176

1,116
1,542

2,658

954
1,576

2,530

536
540

1,076

563
403

966

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 65 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.

e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 7 thousand barrels per day for equity-accounted entities.
f 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.
g Includes 456 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i Includes 54 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft.
j Total proved reserves held as part of our equity interest in Rosneft is 6,702 million barrels of oil equivalent, comprising 1 million barrels of oil equivalent in Canada, 33 million barrels of oil equivalent in

Venezuela, 5 million barrels of oil equivalent in Vietnam and 6,663 million barrels of oil equivalent in Russia.

BP Annual Report and Form 20-F 2014

179

Movements in estimated net proved reserves – continued

Crude oila b

Subsidiaries
At 1 January
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 Decemberd
Developed
Undeveloped

Equity-accounted entities (BP share)e f
At 1 January
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 Decemberg
Developed
Undeveloped

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

228
426
654

At 31 December
Developed
Undeveloped

160
374

534

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asia

million barrels

2013

Total

228
426

654

(79)
11
–
–
(21)
(31)

(120)

160
374

534

–
–

–

–
–
–
–
–
–

–

–
–

–

153
73

226

(15)
–
–
–
(11)
–

(26)

147
53

200

1,127
818

1,945

(111)
33
–
2
(108)
(1)

(185)

1,007
752

1,760

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

153
73
226

147
53

200

1,127
818
1,945

1,007
752

1,760

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

1
–
–
–
–
–

–
1

–
–
–

–
1

16
20

1
1
–
–
(7)
–

(5)

15
17

336
347

683

(14)
27
34
12
(27)
(85)

(53)

316
314

630

352
367
719

331
331

661

306
236

542

30
2
–
–
(79)
–

(47)

316
180

495

3
2

(1)
–
–
–
–
–

(1)

2
2

309
239
547

317
182

499

–
–

–

–
–
–
–
–
–

–

–
–

–

2,433
1,943

4,376

295
–
4,550
228
(301)
(4,321)

451

2,970
1,858

4,828

2,433
1,943
4,376

2,970
1,858

4,828

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

45
34

(5)
–
–
3
(8)
–

(10)

49
19

–
–

–

–
–
–
–
–
–

–

–
–

–

45
34
79

49
19

2,143
1,743

3,886

(114)
112
–
44
(285)
(32)

(276)

2,013
1,597

3,610

2,970
2,305

5,275

281
27
4,584
240
(412)
(4,406)

314

3,407
2,182

5,590

5,113
4,048
9,162

5,421
3,779

9,200

option and ability to make lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 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.

d Includes 8 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 23 million barrels of crude oil in respect of the 0.47% non-controlling interest in Rosneft.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,860 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 32 million barrels in Venezuela and

4,827 million barrels in Russia.

180

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Natural gas liquidsa b

Subsidiaries
At 1 January
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 Decemberd
Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January
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 Decemberf
Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

million barrels

2013

Total

14
5

1
1
–
–
(1)
(5)

(4)

9
6

–
–

–

–
–
–
–
–
–

–

–
–

–

Rest of
Europe

17
6

(4)
–
–
–
(1)
–

(5)

16
2

–
–

–

–
–
–
–
–
–

–

–
–

–

17
6
23

16
2

Rest of
North
America

Russia

Rest of
Asia

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–
–

–
–

–

6
12

29
–
–
–
(4)
–

14
28

3
4

(7)
–
–
–
–
–

(7)

–
–

–

9
16
25

14
28

6
19

(4)
–
–
–
(1)
–

(5)

4
15

9
9

(2)
–
–
–
–
–

(2)

8
8

15
27
43

13
23

–
–

–

–
–
–
–
–
–

–

–
–

–

59
19

89
–
29
–
(2)
(78)

94
21

115

59
19
78

94
21

115

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–
–

–
–

–

316
171

487

(30)
19
–
2
(24)
(10)

(43)

290
155

444

–
–

–

–
–
–
–
–
–

–

–
–

–

316
171
487

290
155

444

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

7
11

(7)
–
–
–
(1)
–

(8)

8
3

–
–

–

–
–
–
–
–
–

–

–
–

–

7
11
18

8
3

366
225

591

(15)
20
–
2
(33)
(15)

(40)

342
209

551

71
32

103

81
–
29
–
(3)
(78)

103
29

131

437
257
693

444
238

682

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

14
5
19

At 31 December
Developed
Undeveloped

9
6

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c Excludes NGLs from processing plants in which an interest is held of 5,500 barrels per day.
d Includes 13 million barrels of NGL 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 Total proved NGL reserves held as part of our equity interest in Rosneft is 115 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 115 million barrels in Russia.

BP Annual Report and Form 20-F 2014

181

Movements in estimated net proved reserves – continued

Bitumena b

Subsidiaries
At 1 January
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
Developed
Undeveloped

million barrels

2013

Total

–
195

195

(7)
–
–
–
–
–

(7)

–
188

188

Rest of
North
America

–
195

195

(7)
–
–
–
–
–

(7)

–
188

188

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.

182

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Total liquidsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place

At 31 Decembere
Developed
Undeveloped

Equity-accounted entities (BP share)f
At 1 January
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 Decemberg h

Developed
Undeveloped

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

242
431

At 31 December
Developed
Undeveloped

673

169
380

549

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asia

million barrels

2013

Total

242
431

673

(78)
12
–
–
(22)
(36)

(124)

169
380

549

–
–

–

–
–
–
–
–
–

–

–
–

–

170
79

249

1,444
989

2,433

–
195

195

(19)
–
–
–
(13)
–

(31)

(141)
52
–
3
(132)
(12)

(229)

(7)
–
–
–
–
–

(7)

163
55

217

1,297
907

2,204

–
188

188

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

1
–
–
–
–
–

–
1

170
79

249

163
55

217

1,444
989

2,433

1,297
907

2,204

–
195

195

–
188

189

22
32

30
1
–
–
(11)
–

29
46

339
351

691

(21)
27
34
11
(27)
(85)

(61)

316
314

630

361
384

745

345
359

704

312
255

567

26
2
–
–
(80)
–

(52)

320
195

515

12
11

(3)
–
–
–
–
–

(3)

10
10

324
266

590

331
205

535

–
–

–

–
–
–
–
–
–

–

–
–

–

2,492
1,962

4,453

384
–
4,579
228
(302)
(4,399)

490

3,063
1,879

4,943

2,492
1,962

4,453

3,063
1,879

4,943

268
137

405

65
65
–
39
(52)
–

117

320
202

523

198
13

211

1
–
–
–
(85)
–

(84)

120
7

127

466
150

616

440
209

650

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

52
45

(12)
–
–
3
(9)
–

(18)

57
22

–
–

–

–
–
–
–
–
–

–

–
–

–

52
45

57
22

2,509
2,164

4,673

(136)
132
–
45
(319)
(48)

(324)

2,354
1,994

4,348

3,041
2,337

5,378

362
27
4,613
239
(414)
(4,485)

343

3,510
2,210

5,721

5,550
4,501

10,051

5,865
4,204

10,069

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 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.

d Excludes NGLs from processing plants in which an interest is held of 5,500 barrels per day.
e Also includes 21 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 23 million barrels in respect of the non-controlling interest in Rosneft.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 4,975 million barrels, comprising 1 million barrels in Canada, 32 million barrels in Venezuela, less than 1 million barrels in

Vietnam and 4,943 million barrels in Russia.

BP Annual Report and Form 20-F 2014

183

Movements in estimated net proved reserves – continued

Europe

Rest of
Europe

North
America

Rest of
North
America

South
America

Africa

Asia

Australasia

billion cubic feet

2013

Total

Russia

Rest of
Asia

Natural gasa b

Subsidiaries
At 1 January
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 Decemberd
Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January
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 Decemberf g

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)

(1,166)
630
–
39
(635)
(152)

(1,284)

364
39

403

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)
–

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

4
–

10
–
–
–
(4)
–

10
–

–
–

–

1
–
–
–
–
–

–
1

4
–

10
1

3,282
2,323

5,605

18,562
14,702

33,264

(140)
–
–
511
(289)
–

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
Developed
Undeveloped

1,038
666

At 31 December
Developed
Undeveloped

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

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 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.
d Includes 2,685 billion cubic feet of natural gas 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 41 billion cubic feet of natural gas in respect of the 0.44% non-controlling interest in Rosneft.
g 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.

184

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Total hydrocarbonsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place

At 31 Decemberg
Developed

Undeveloped

Equity-accounted entities (BP share)h
At 1 January
Developed

Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionf
Sales of reserves-in-place

At 31 Decemberi j

Developed

Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USd

Rest of
North
America

Russia

Rest of
Asia

2013

Total

million barrels of oil equivalentc

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

287

–

–
–
–
–
–
–

–

(342)
161
–
10
(241)
(38)

(450)

(5)
–
–
–
(1)
–

(6)

2,525

1,394

3,919

188

190

–

–
–
–
–
–
–

–

1
–
–
–
–
–

–

–
–

–

–
–
–
–
–
–

–

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

235

1
1
6
–
(88)
(13)

(93)

133

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

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

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

2
–
–
–
(1)
–

551
626

1,177

536

540

1,076

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

421
546

At 31 December
Developed

Undeveloped

967

280

434

714

229
103

332

225

287

2,865
1,504

4,369

2,525

1,394

3,919

1
195

196

189

191

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d 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.

e Excludes NGLs from processing plants in which an interest is held of 5,500 barrels of oil equivalent per day.
f 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.
g Includes 484 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i Includes 30 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft.
j 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.

BP Annual Report and Form 20-F 2014

185

Movements in estimated net proved reserves – continued

Crude oila b

Subsidiaries
At 1 January
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 Decemberd e

Developed
Undeveloped

Equity-accounted entities (BP share)f
At 1 January
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 Decemberg h i

Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asia

million barrels

2012

Total

276
436

712

(30)
3
4
–
(30)
(6)

(59)

228
426

654

–
–

–

–
–
–
–
–
–

–

–
–

–

66
208

274

1,337
1,021

2,357

(23)
–
–
1
(8)
(18)

(48)

(288)
77
4
10
(115)
(101)

(412)

153
73

226

1,127
818

1,945

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

66
208

274

153
73

226

1,337
1,021

2,357

1,127
818

1,945

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

23
30

(11)
–
–
–
(6)
–

(17)

16
20

345
344

689

(2)
24
–
–
(29)
–

(7)

336
347

683

368
375

743

352
367

719

304
294

598

(1)
13
–
2
(70)
–

(56)

306
236

542

–
3

3
–
–
–
–
–

3
2

304
297

601

309
239

547

–
–

–

–
–
–
–
–
–

–

–
–

–

2,596
1,613

4,209

377
47
–
67
(309)
(15)

167

2,433
1,943

4,376

2,596
1,613

4,209

2,433
1,943

4,376

176
279

455

(2)
2
–
–
(51)
–

(51)

268
137

405

256
58

314

(23)
–
–
–
(80)
–

(103)

198
13

211

432
337

769

466
150

616

50
36

–
–
–
–
(8)
–

(8)

45
34

–
–

–

–
–
–
–
–
–

–

–
–

–

50
36

45
34

2,233
2,304

4,537

(354)
95
8
12
(287)
(124)

(650)

2,143
1,743

3,886

3,197
2,018

5,215

355
71
–
67
(418)
(15)

2,970
2,305

5,275

5,430
4,322

9,752

5,113
4,048

9,162

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

276
436

At 31 December
Developed
Undeveloped

712

228
426

654

option and ability to make lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 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.

d Includes 9 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Includes assets held for sale of 39 million barrels.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 328 million barrels of crude oil in respect of the 7.35% non-controlling interest in TNK-BP.
h Total proved crude oil reserves held as part of our equity interest in TNK-BP is 4,463 million barrels, comprising 87 million barrels in Venezuela and 4,376 million barrels in Russia.
i Includes assets held for sale of 4,463 million barrels.

186

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Natural gas liquidsa b

Subsidiaries
At 1 January
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 Decemberd
Developed
Undeveloped

Equity-accounted entities (BP share)e
At 1 January
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 Decemberf g

Developed
Undeveloped

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

12
9

At 31 December
Developed
Undeveloped

14
5

Europe

North
America

South
America

Africa

Asia

Australasia

million barrels

2012

Total

12
9

–
–
–
–
(1)
–

(1)

14
5

–
–

–

–
–
–
–
–
–

–

–
–

–

Rest of
Europe

3
22

(2)
–
–
–
–
–

(2)

17
6

–
–

–

–
–
–
–
–
–

–

–
–

–

3
22

17
6

Rest of
North
America

Russia

Rest of
Asia

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

4
18

–
–
–
–
(4)
–

(4)

6
12

4
4

–
–
–
–
–
–

–

3
4

8
21

9
16

7
21

–
–
–
–
(3)
–

(3)

6
19

–
11

6
–
–
–
–
–

9
9

7
32

15
27

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

85
–
–
–
(7)
–

59
19

–
–

–

59
19

1
–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

1
–

–
–

–

348
152

501

8
63
17
13
(27)
(87)

(14)

316
171

487

–
–

–

–
–
–
–
–
–

–

–
–

–

348
152

501

316
171

487

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

9
11

–
–
–
–
(1)
–

(1)

7
11

–
–

–

–
–
–
–
–
–

–

–
–

–

9
11

7
11

383
233

616

5
63
17
14
(37)
(88)

(26)

366
225

591

4
15

91
–
–
–
(7)
–

71
32

103

387
248

635

437
257

693

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c Excludes NGLs from processing plants in which an interest is held of 13,500 barrels per day.
d Includes 5 million barrels of NGL 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 Total proved NGL reserves held as part of our equity interest in TNK-BP is 78 million barrels, all in Russia.
g Includes assets held for sale of 78 million barrels.

BP Annual Report and Form 20-F 2014

187

Movements in estimated net proved reserves – continued

Bitumena b

Subsidiaries
At 1 January
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
Developed
Undeveloped

million barrels

2012

Total

–
178

178

17
–
–
–
–
–

–
195

195

Rest of
North
America

–
178

178

17
–
–
–
–
–

–
195

195

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.

188

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Total liquidsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place

At 31 Decembere f

Developed
Undeveloped

Equity-accounted entities (BP share)g
At 1 January
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 Decemberh i j

Developed
Undeveloped

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

287
445

At 31 December
Developed
Undeveloped

733

242
431

673

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asia

million barrels

2012

Total

287
445

733

(29)
3
4
–
(31)
(6)

(59)

242
431

673

–
–

–

–
–
–
–
–
–

–

–
–

–

69
230

299

(25)
–
–
1
(8)
(18)

(51)

170
79

249

1,686
1,173

2,859

(280)
140
21
23
(141)
(188)

(425)

1,444
989

2,433

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
178

178

18
–
–
–
–
–

–
195

195

–
–

–

–
–
–
–
–
–

–

–
–

–

69
230

299

170
79

249

1,686
1,173

2,859

1,444
989

2,433

–
178

178

–
195

195

27
48

(11)
–
–
–
(10)
–

(21)

22
32

349
348

697

(2)
24
–
–
(29)
–

(7)

339
351

691

376
396

772

361
384

745

311
314

625

(1)
13
–
2
(72)
–

(59)

312
255

567

–
14

9
–
–
–
–
–

12
11

311
328

640

324
266

590

–
–

–

–
–
–
–
–
–

–

–
–

–

2,595
1,614

4,209

462
47
–
67
(316)
(15)

244

2,492
1,962

4,453

2,595
1,614

4,209

2,492
1,962

4,453

177
279

456

(2)
2
–
–
(51)
–

(51)

268
137

405

256
58

314

(24)
–
–
–
(80)
–

(103)

198
13

211

433
337

770

466
150

616

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

59
47

106

–
–
–
–
(9)
–

(10)

52
45

–
–

–

–
–
–
–
–
–

–

–
–

–

2,617
2,714

5,331

(331)
158
24
26
(324)
(212)

(658)

2,509
2,164

4,673

3,201
2,034

5,234

445
71
–
67
(425)
(15)

144

3,041
2,337

5,378

59
47

5,817
4,748

106

10,565

52
45

5,550
4,501

10,051

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
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 Also includes 14 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Includes assets held for sale of 4,540 million barrels.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 328 million barrels in respect of the non-controlling interest in TNK-BP.
i 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.
j Includes assets held for sale of 39 million barrels.

BP Annual Report and Form 20-F 2014

189

Movements in estimated net proved reserves – continued

Natural gasa b

Subsidiaries
At 1 January
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 Decemberd e

Developed
Undeveloped

Equity-accounted entities (BP share)f
At 1 January
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 Decemberg h i

Developed
Undeveloped

Europe

Rest of
Europe

North
America

Rest of
North
America

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
–

(19)
–
–
–
(5)
–

(24)

4
–

–
–

–

–
–
–
–
–
–

–

–
–

–

28
–

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)
–

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
Developed
Undeveloped

1,411
909

At 31 December
Developed
Undeveloped

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

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 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.

d Includes 2,890 billion cubic feet of natural gas in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Includes assets held for sale of 590 billion cubic feet.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 270 billion cubic feet of natural gas in respect of the 6.17% non-controlling interest in TNK-BP.
h 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.

i Includes assets held for sale of 4,492 billion cubic feet.

190

BP Annual Report and Form 20-F 2014

Movements in estimated net proved reserves – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USd

Rest of
North
America

Russia

Rest of
Asia

2012

Total

million barrels of oil equivalentc

Total hydrocarbonsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place

At 31 Decemberg h

Developed
Undeveloped

Equity-accounted entities (BP share)i
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place

At 31 Decemberj k l

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)
–

1
195

196

–
–

–

–
–
–
–
–
–

–

–
–

–

522
1,173

1,695

522
665

1,187

(31)
130
–
103
(143)
(4)

(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

34
–
–
–
–
–

43
39

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

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

629
408
1,037

647
224

871

675
455
1,130

9,829
7,919
17,748

618
445

9,474
7,526

1,063

17,000

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

531
602
1,133

At 31 December
Developed
Undeveloped

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

and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their counterparts.
c 5.8 billion cubic feet of natural gas = 1 million barrels of oil equivalent.
d 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.

e Excludes NGLs from processing plants in which an interest is held of 13,500 barrels of oil equivalent per day.
f 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.

g 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.
h Includes assets held for sale of 140 million barrels of oil equivalent.
i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
j Includes 103 million barrels of NGLs. Also includes 374 million barrels of oil equivalent in respect of the non-controlling interest in TNK-BP.
k 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.

l Includes assets held for sale of 5,315 million barrels of oil equivalent.

BP Annual Report and Form 20-F 2014

191

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

South
America

North
America

Rest of
North
America

Africa

Asia

Australasia

$ million

2014

Total

Russia

Rest of
Asia

At 31 December
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc

Future net cash flows
10% annual discountd

54,400
21,400
7,300
16,400

9,300
4,700

14,900
8,100
1,400
3,000

2,400
700

216,600
90,500
24,500
32,900

68,700
33,100

11,000
4,800
1,600
700

3,900
2,500

35,300
11,300
8,000
8,400

7,600
3,100

55,800
15,600
9,600
10,100

20,500
7,800

Standardized measure of discounted

future net cash flowse

4,600

1,700

35,600

1,400

4,500

12,700

–
–
–
–

–
–

–

90,300
41,500
23,000
5,100

20,700
11,000

54,800
17,600
5,700
9,400

22,100
11,800

533,100
210,800
81,100
86,000

155,200
74,700

9,700

10,300

80,500

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

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

47,300
22,300
5,700
6,700

12,600
8,000

4,600

–
–
–
–

–
–

–

349,200
200,000
17,400
24,200

107,600
65,500

10,200
7,800
2,100
100

200
–

42,100

200

–
–
–
–

–
–

–

406,700
230,100
25,200
31,000

120,400
73,500

46,900

discounted future net cash flows

4,600

1,700

35,600

1,400

9,100

12,700

42,100

9,900

10,300

127,400

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

(30,500)
15,700
1,900
(17,000)
1,200
17,300
(4,500)
(700)
8,800

(7,800)

(6,900)
3,600
1,500
10,500
2,000
(4,900)
(400)
–
3,800

9,200

(37,400)
19,300
3,400
(6,500)
3,200
12,400
(4,900)
(700)
12,600

1,400

a The marker prices used were Brent $101.27/bbl, Henry Hub $4.31/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 interests in BP Trinidad and Tobago LLC amounted to $1,400 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 interests in Rosneft amounted to $100 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. Exchange rate effects arising from the translation of our share of Rosneft changes to

US dollars are included within ‘Net changes in prices and production cost’.

192

BP Annual Report and Form 20-F 2014

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2013

Total

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

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

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

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

At 31 December
Subsidiaries
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 flowse

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

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:

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 interests 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 interests 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 2014

193

F
i
n
a
n
c
i
a
l
s
t
a
t
e
m
e
n
t
s

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas reserves – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2012

Total

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

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

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

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

At 31 December
Subsidiaries
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 flowse

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

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:

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 interests 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 interests 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.

194

BP Annual Report and Form 20-F 2014

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, natural gas liquids and natural gas production for the years ended 31 December 2014, 2013 and 2012.
Production for the yeara b

Europe

North
America

South
America

Africa

Asia

Australasia

Total

Subsidiaries

Crude oild

2014
2013
2012

Natural gas liquids

2014
2013
2012

Natural gase

2014
2013
2012

Equity-accounted entities (BP share)

Crude oild

2014
2013
2012

Natural gas liquids

2014
2013
2012

Natural gase

2014
2013
2012

46
58
81

2
3
5

71
157
414

–
–
–

Rest of
Europe

41
31
22

5
4
1

347
305
327

63
58
64

102
80
8

1,519
1,539
1,651

–
–
–

Rest of
North
America

Russiac

Rest of
Asia

–
–
–

–
–
1

10
11
13

–
–
–

13
17
16

12
12
13

2,147
2,221
2,097

65
62
64

3
3
3

402
384
390

222
217
191

5
3
7

513
561
590

–
–
–

4
5
5

–
–
–

816
826
857

5
11
20

1,084
801
785

156
141
137

–
1
2

408
490
633

98
232
217

–
–
–

28
30
26

thousand barrels per day

19
21
22

844
789
795

thousand barrels per day

3
4
4

91
86
96

million cubic feet per day

814
784
787

5,585
5,845
6,193

thousand barrels per day

–
–
–

979
1,120
1,137

thousand barrels per day

–
–
–

12
19
27

million cubic feet per day

–
–
–

1,515
1,216
1,200

F
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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 Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Amounts reported for Russia include BP’s share of Rosneft (2014, 2013), and TNK-BP (2012) worldwide activities, including insignificant amounts outside Russia.
d Crude oil includes condensate.
e Natural gas production excludes gas consumed in operations.
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 2014. 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

North
America

Rest of
North
America

Number of productive wells at 31 December 2014

Oil wellsb

Gas wellsc

– gross
– net
– gross
– net

116
71
67
28

65
26
6
1

Oil and natural gas acreage at 31 December 2014

Developed

Undevelopedd

– gross
– net
– gross
– net

131
73
1,208
755

39
16
1,754
648

2,407
823
22,676
9,339

6,355
3,285
7,378
5,365

119
31
363
180

232
110
9,702
5,564

South
America

4,752
2,620
728
262

1,365
407
28,183
11,593

Africa

Asia

Australasia

Total

Russiaa

Rest of
Asia

634
446
139
53

44,548
8,798
383
76

936
302
833
314

637
223
33,833
21,799

4,581
865
378,899
74,009

837
259
6,988
2,302

12
2
61
13

53,589
13,119
25,256
10,266

Thousands of acres

194
36
20,050
10,755

14,371
5,274
487,995
132,790

a Based on information received from Rosneft as at 31 December 2014.
b Includes approximately 11,271 gross (2,237 net) multiple completion wells (more than one formation producing into the same well bore).
c Includes approximately 3,239 gross (1,482 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.
d Undeveloped acreage includes leases and concessions.

BP Annual Report and Form 20-F 2014

195

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.

Europe

North
America

South
America

Africa

Asia

Australasia

Total

2014
Exploratory

Productive
Dry

Development
Productive
Dry
2013
Exploratory

Productive
Dry

Development
Productive
Dry
2012
Exploratory

Productive
Dry

Development
Productive
Dry

2.9
0.5

3.1
–

1.0
–

–
0.2

1.6
–

Rest of
Europe

–
–

5.3
7.9

1.8
0.8

294.1
–

–
–

12.7
1.1

1.2
0.2

285.7
0.4

0.3
–

17.1
0.6

–
–

317.8
–

Rest of
North
America

Russia

Rest of
Asia

–
–

1.5
0.1

3.7
1.4

100.5
3.9

0.7
1.6

13.8
1.0

5.3
–

76.2
–

0.6
1.4

46.3
0.4

3.5
0.9

58.0
0.7

–
0.2

–
0.4

–
0.5

0.2
0.4

18.5
13.0

537.3
6.6

27.2
4.5

848.3
4.6

1.5
0.6

4.0
–

12.6
0.2

395.0
–

2.3
0.5

14.7
5.0

–
–

17.7
1.0

552.5
–

43.1
9.5

–
–

40.2
7.3

1,011.6
10.5

–
–

4.5
1.4

94.6
2.7

5.8
1.0

78.9
–

Drilling and production activities in progress
The following table shows the number of exploratory and development oil and natural gas wells in the process of being drilled by the group and its
equity-accounted entities as of 31 December 2014. Suspended development wells and long-term suspended exploratory wells are also included in the
table.

Europe

North
America

South
America

Africa

Asia

Australasia

Total

At 31 December 2014
Exploratory
Gross
Net

Development

Gross
Net

–
–

2.0
1.1

Rest of
Europe

–
–

7.0
5.6

1.0
0.4

339.0
119.6

Rest of
North
America

–
–

1.0
0.1

Russia

Rest of
Asia

3.0
0.6

47.0
17.7

6.0
4.0

25.0
6.6

–
–

66.0
22.5

1.0
0.2

15.0
1.4

17.0
10.4

496.0
169.4

196

BP Annual Report and Form 20-F 2014

Parent company financial statements of BP p.l.c.
Company balance sheet
At 31 December

Note

2014

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 (deficit) surplus
Defined benefit pension plan (deficit) surplus

Net assets

Represented by
Capital and reserves

Called-up share capital
Share premium account
Capital redemption reserve
Merger reserve
Treasury shares
Profit and loss account

3
3

4
2

7
8
8
8
8
8

$ million

2013

134,125
2

134,127

21,550
41
6

21,597
4,267

17,330

151,457
4,642

146,815
979

147,794

139,239
2

139,241

7,159
–
31

7,190
2,867

4,323

143,564
4,653

138,911
(584)

138,327

5,023
10,260
1,413
26,509
(20,719)
115,841

5,129
10,061
1,260
26,509
(20,971)
125,806

138,327

147,794

F
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The financial statements on pages 197–206 were approved and signed by the group chief executive on 3 March 2015 having been duly authorized to
do so by the board of directors:

R W Dudley Group Chief Executive

The parent company financial statements of BP p.l.c. on pages 197-206 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 2014

197

Company cash flow statement
For the year ended 31 December

Net cash inflow (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

Increase (decrease) in cash

Company statement of total recognized gains and losses
For the year ended 31 December

Profit for the year
Currency translation differences
Actuarial (loss) gain relating to pensions
Tax on actuarial (loss) gain relating to pensions

Total recognized gains and losses relating to the year

Note

2014

$ million

2013

13,253

(4,813)

192
(23)
2,129

2,298

(1)

116
(43)
16,228

16,301

(2)

(5,085)

(690)

(5,850)

(5,441)

4,615

5,355

207
(4,797)

(4,590)

135
(5,493)

(5,358)

(3)

Note

2014

2,100
31
(2,634)
41

6
2

$ million

2013

15,691
47
2,108
(41)

(462)

17,805

The parent company financial statements of BP p.l.c. on pages 197-206 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

198

BP Annual Report and Form 20-F 2014

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. A corresponding credit is recognized within equity. Fair value is determined by using an appropriate,
widely used, 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 recognized as an expense over the vesting period, measured by reference to the fair value of the corresponding
liability which is recognized on the balance sheet. The liability is remeasured at each balance sheet date until settlement, with changes in fair value
recognized in the income statement.

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. Deferred benefit pension plan surpluses are
only recognized to the extent they are recoverable.

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.

The parent company financial statements of BP p.l.c. on pages 197-206 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 2014

199

F
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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
Charge (credit) for the year on ordinary activities
(Credit) charge for the year in the statement of total recognized gains and losses

At 31 December

$ million

2014

2013

–

(41)
41

41
(41)

–

–
–

–
41
(41)
–

41
–

–
(41)
41
–

At 31 December 2014, deferred tax assets of $95 million on other timing differences and $25 million on pensions (2013 $72 million on other timing
differences) 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 2014
Additions
Disposals

At 31 December 2014
Amounts provided

At 1 January 2014
Disposals

At 31 December 2014
Cost

At 1 January 2013
Additions

At 31 December 2013
Amounts provided

At 1 January 2013
At 31 December 2013
Net book amount

At 31 December 2014
At 31 December 2013

Subsidiary
undertakings

Associated
undertakings

Loans

Total

$ million

134,199
5,114
–
139,313

74
–
74

133,494
705
134,199

74
74

139,239
134,125

2
–
–
2

–
–
–

2
–
2

–
–

2
2

2
–
(2)
–

2
(2)
–

2
–
2

2
2

–
–

134,203
5,114
(2)
139,315

76
(2)
74

133,498
705
134,203

76
76

139,241
134,127

The more important subsidiary undertakings of the company at 31 December 2014 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.

Subsidiary undertakings

International

BP Corporate Holdings
BP Global Investments
BP International
BP Shipping
Burmah Castrol

Canada

BP Holdings Canada

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

100

England & Wales

Investment holding

BP Holdings North America

100

England & Wales

Investment holding

The carrying value of BP International in the accounts of the company at 31 December 2014 was $67.63 billion (2013 $62.63 billion).
The parent company financial statements of BP p.l.c. on pages 197-206 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

200

BP Annual Report and Form 20-F 2014

4. Debtors

Group undertakings

The carrying amounts of debtors approximate their fair value.

5. Creditors

Group undertakings
Accruals and deferred income
Other creditors

2014

Within
1 year

7,159

Within
1 year

2,476
391
–

2,867

2014

After
1 year

4,563
90
–

4,653

Within
1 year

2,526
1,540
201

4,267

$ million

2013

Within
1 year

21,550

$ million

2013

After
1 year

4,584
58
–

4,642

The carrying amounts of creditors approximate their fair value.

Amounts falling due after one year include $4,236 million (2013 $4,236 million), payable to a group undertaking. This amount is subject to interest
payable quarterly at LIBOR plus 55 basis points.

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

6. Pensions

2014

404
13
4,236

4,653

$ million

2013

372
22
4,248

4,642

F
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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 corporate trustee whose board is composed of four member-nominated directors, four company-nominated
directors, including an independent director and an independent chairman nominated by the company. 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. 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.

For the primary UK plan there is a funding agreement between the company and the trustee. On an annual basis the latest funding position is reviewed
and a schedule of contributions covering the next five years is agreed. The funding agreement can be terminated unilaterally by either party with two
years’ notice. The minimum funding requirement therefore represents seven years of future contributions, which amounted to $4,720 million at 31
December 2014. There are no such minimum funding requirements after this seven-year period, and the obligation is taken into account in the
determination of the amount of any pension plan surplus recognized on the balance sheet.

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 2014. 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, and a valuation as at 31 December 2014 is currently under way.

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 benefits at 31 December and pension expense for the following year.

Financial assumptions used to determine benefit obligation

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
Expected long-term rate of return
Inflation for pension plan service costs

2014

2013

2012

3.6
4.5
3.0
3.0
3.0

4.6
5.1
3.3
3.3
3.3

4.4
4.9
3.1
3.1
3.1

2014

2013

2012

4.8
4.6
6.9
3.4

4.4
4.4
6.9
3.1

4.8
4.8
6.9
3.2

The parent company financial statements of BP p.l.c. on pages 197-206 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 2014

201

6. Pensions – continued

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

2014

28.3
30.9
29.4
31.8

2013

27.8
30.7
29.5
32.2

2012

27.7
30.6
29.4
32.1

The assets of the principal plan are held in a trust. The primary objective of the trust is to accumulate pools of assets sufficient to meet the obligations
of the plan. 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 of such assets 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 fair values of the various categories of asset held by the defined benefit plans at 31 December are set out below.

Listed equity – developed
– emerging

Private equity
Government issued nominal bondsa
Index-linked bondsa
Corporate bondsa
Propertyb
Cash
Other

Present value of plan liabilities

(Deficit) surplus in the plans

Expected
long-term
rate of
return
%

8.0
8.0
8.0
3.3
3.3
3.3
6.5
0.9
0.9

6.7

2014

2013

2012

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

Market
value
$ million

16,190
2,719
2,983
642
892
4,687
2,403
1,145
112

31,773
32,357

(584)

Market
value
$ million

17,341
2,290
2,907
549
787
4,427
2,200
855
160

31,516
30,496

1,020

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

Market
value
$ million

15,659
1,074
2,879
544
491
3,850
1,783
1,000
66

27,346
29,259

(1,913)

a Bonds held are denominated in sterling.
b Property held is all located in the United Kingdom.
The main pension plan does not invest directly in either securities or property/real estate of the company or of any subsidiary. Some of the 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 over time, with a view to better matching of the asset portfolio with the pension liabilities.
The company’s principal plan in the UK does not currently follow a liability driven investment approach, a form of investing designed to match the
movement in pension plan assets with the movement in projected benefit obligations over time.

Analysis of the amount charged to operating profit

Current service costa
Settlement, curtailment and special termination benefits
Payments to defined contribution plans

Total operating charge

Analysis of the amount credited 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 (loss) gain recognized in statement of total recognized gains and losses

2014

2013

494
–
30

524

2,147
(1,375)

772

547
(3,139)
(42)
(2,634)

497
(22)
24

499

1,803
(1,221)

582

2,007
60
41
2,108

a The costs of managing the fund’s investments are offset against the investment return. The costs of administering our pensions plan benefits are included in current service cost.
The parent company financial statements of BP p.l.c. on pages 197-206 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

202

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6. Pensions – continued

Movements in benefit obligation during the year

Benefit obligation at 1 January
Exchange adjustment
Current service costa
Interest cost
Curtailments
Disposals
Past Service Cost
Contributions by plan participantsd
Benefit payments (funded plans)b
Benefit payments (unfunded plans)b
Actuarial loss (gain) 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 c
Contributions by plan participantsd
Contributions by employers (funded plans)
Disposals
Benefit payments (funded plans)b
Actuarial gain on plan assetsc

Fair value of plan assets at 31 Decembere

(Deficit) surplus at 31 December

2014

2013

30,496
(1,989)
494
1,375
–
–
–
39
(1,231)
(8)
3,181

32,357

31,516
(1,958)
2,147
39
713
–
(1,231)
547

31,773

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

(584)

1,020

a The costs of managing the fund’s investments are offset against the investment return, the costs of administering our pensions plan benefits are included in current service cost.
b The benefit payments amount shown above comprises $1,218 million benefits plus $21 million of plan expenses incurred in the administration of the benefit.
c 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.
d The contributions by plan participants for the UK are mostly comprised of contributions made under salary sacrifice arrangements.
e Reflects $31,600 million of assets held in the BP Pension Fund (2013 $31,362 million) and $134 million held in the BP Global Pension Trust (2013 $114 million), with $39 million representing the

company’s share of Merchant Navy Officers Pension Fund (2013 $40 million).

Reconciliation of plan (deficit) surplus to balance sheet

(Deficit) surplus at 31 December
Deferred tax

Represented by

Plans in surplus
Plans in deficit

2014

2013

(584)
–

(584)

15
(599)

(584)

1,020
(41)

979

1,238
(259)

979

The aggregate level of employer contributions into the BP Pension Fund in 2015 is expected to be $519 million.

History of (deficit) surplus and of experience gains and losses

Benefit obligation at 31 December
Fair value of plan assets at 31 December

(Deficit) surplus

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 (loss) gain 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

2014

2013

2012

2011

2010

32,357
31,773

(584)

30,496
31,516

1,020

29,259
27,346

(1,913)

25,675
23,587

(2,088)

20,742
22,612

1,870

(42)
0%

547
2%

(2,634)
(8)%
(7,104)

41
0%

(116)
0%

(84)
0%

12
0%

2,007
6%

2,108
7%
(4,470)

989
4%

(1,976)
(8)%

1,479
7%

(573)
(2)%
(6,578)

(4,770)
(19)%
(6,005)

457
2%
(1,235)

The parent company financial statements of BP p.l.c. on pages 197-206 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 2014

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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

Shares
(thousand)

7,233
5,473

20,426,632
165,644
25,598
(611,913)

20,005,961

2014

$ million

12
9

5,108
41
6
(153)

5,002

5,023

Shares
(thousand)

7,233
5,473

20,959,159
202,124
18,203
(752,854)

20,426,632

2013

$
million

12
9

5,240
51
5
(188)

5,108

5,129

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 $207 million (2013 $116 million and 2012 $47 million).
c Purchased for a total consideration of $4,796 million, including transaction costs of $26 million (2013 $5,493 million, including transaction costs of $30 million). All shares purchased were for

cancellation. The repurchased shares represented 3% of ordinary share capital.

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.

8. Capital and reserves

At 1 January 2014
Currency translation differences
Actuarial loss on pensions (net of tax)
Share-based payments
Repurchases of ordinary share capital
Profit for the year
Dividends

At 31 December 2014

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

Share
capital

5,129
–
–
6
(153)
–
41

5,023

Share
capital

5,261
–
–
5
(188)
–
51

5,129

Share
premium
account

10,061
–
–
240
–
–
(41)

10,260

Capital
redemption
reserve

1,260
–
–
–
153
–
–

1,413

Share
premium
account

Capital
redemption
reserve

9,974
–
–
138
–
–
(51)

10,061

1,072
–
–
–
188
–
–

1,260

Merger
reserve

26,509
–
–
–
–
–
–

26,509

Merger
reserve

26,509
–
–
–
–
–
–

26,509

Treasury
shares

(20,971)
–
–
252
–
–
–

(20,719)

Treasury
shares

(21,054)
–
–
83
–
–
–

(20,971)

Profit
and loss
account

125,806
31
(2,593)
(287)
(3,366)
2,100
(5,850)

115,841

Profit
and loss
account

120,161
47
2,067
204
(6,923)
15,691
(5,441)

125,806

$ million

Total

147,794
31
(2,593)
211
(3,366)
2,100
(5,850)

138,327

$ million

Total

141,923
47
2,067
430
(6,923)
15,691
(5,441)

147,794

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 (2013 $24,107 million), the distribution of which is limited by statutory or other restrictions.

The accounts for the year ended 31 December 2014 do not reflect the dividend announced on 3 February 2015 and payable in March 2015; this will be
treated as an appropriation of profit in the year ended 31 December 2015.

The parent company financial statements of BP p.l.c. on pages 197-206 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

204

BP Annual Report and Form 20-F 2014

9. Cash flow

Notes on cash flow statement

Reconciliation of net cash flow to movement of funds

Increase (decrease) in cash

Movement of funds
Net cash at 1 January

Net cash at 31 December

Notes on cash flow statement
Reconciliation of operating profit to net cash inflow (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 (decrease) in creditors

Net cash inflow (outflow) from operating activities

Analysis of movements of funds

Cash at bank

10. Contingent liabilities

2014

25
6

$ million

2013

(3)

(3)
9

2014

2013

1,393
(227)
(2,321)
376
14,391
(359)

13,253

15,112
(127)
(16,414)
297
(4,054)
373

(4,813)

At
1 January
2014

$ million

At
31 December
2014

Cash
flow

The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2014 were $51,463 million (2013 $47,042
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 (credit) 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 9 to the consolidated financial statements.

12. Auditor’s remuneration

Note 34 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
Amounts awarded under incentive schemes

Total

$ million

2013

709
10

719

17
2

2014

770
(81)

689

108
54

$ million

2013

16
2

2014

14
14

The parent company financial statements of BP p.l.c. on pages 197-206 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 2014

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13. Directors’ remuneration – continued

Pension contributions
During 2014, two executive directors participated in a non-contributory pension scheme established for UK staff by a separate trust fund to which
contributions are made by BP based on actuarial advice. One US executive director participated in the US BP Retirement Accumulation Plan during
2014.

Further information
Full details of individual directors’ remuneration are given in the directors’ remuneration report on pages 72-88.

The parent company financial statements of BP p.l.c. on pages 197-206 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

206

BP Annual Report and Form 20-F 2014

Additional
disclosures

208 Selected financial information

211 Liquidity and capital resources

213 Upstream analysis by region

217 Downstream plant capacity

219 Oil and gas disclosures for the group

225 Environmental expenditure

225 Regulation of the group’s business

228 Legal proceedings

238 International trade sanctions

239 Material contracts

239 Property, plant and equipment

239 Related-party transactions

239 Corporate governance practices

240 Code of ethics

240 Controls and procedures

241 Principal accountants’ fees and services

241 Directors’ report information

241 Disclosures required under Listing Rule 9.8.4R

241 Cautionary statement

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BP Annual Report and Form 20-F 2014

207

Selected financial information
This information, insofar as it relates to 2014, has been extracted or derived from the audited consolidated financial statements of the BP group
presented on page 89. 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.

Income statement data

Sales and other operating revenues
Underlying replacement cost (RC) profit before interest and taxation*
Net favourable (unfavourable) impact of non-operating items* and fair value

accounting effects*

RC profit (loss) before interest and taxation*
Inventory holding gains (losses)*
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) losses, net of taxation

RC profit (loss) for the year attributable to BP shareholders
Non-operating items and fair value accounting effects, net of taxation

Underlying RC profit for the year attributable to BP shareholders

Per ordinary share – cents

Profit (loss) for the year attributable to BP shareholders

Basic
Diluted

RC profit (loss) for the year attributable to BP shareholders
Underlying RC profit for the year attributable to BP shareholders

Dividends paid per share – cents
– pence

Capital expenditure and acquisitions, on an accruals basis
Acquisitions and asset exchanges, on an accruals basis
Organic capital expenditure*a, on an accruals basis
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 equity*
Ordinary share datab

Basic weighted average number of shares
Diluted weighted average number of shares

2014

2013

2012

2011

2010

$ million except per share amounts

353,568

379,136

375,765

375,713

297,107

20,818

22,776

26,454

33,601

31,704

(8,196)

12,622
(6,210)

6,412

(1,462)
(947)

4,003

3,780
4,293

8,073
4,063

12,136

20.55
20.42
43.90
66.00

39.00
23.850

23,781
420
22,892

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)

(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

284,305
112,642
5,023
111,441
45,977
16.7%

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%

Shares million

18,385
18,497

18,931
19,046

19,028
19,158

18,905
19,136

18,786
18,998

a Organic capital expenditure excludes acquisitions and asset exchanges, and: in 2014 $469 million relating to the purchase of an additional 3.3% equity in Shah Deniz, Azerbaijan and the South Caucasus

Pipeline; 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.

b The number of ordinary shares shown has been used to calculate the per share amounts.

208

BP Annual Report and Form 20-F 2014

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 assetsa
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Otherb

Downstream
Impairment and gain (loss) on sale of businesses and fixed assetsa
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
Otherc

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 assetsa
Environmental and other provisions
Restructuring, integration and rationalization costs
Fair value gain (loss) on embedded derivatives
Otherd

Gulf of Mexico oil spill response

Total before interest and taxation
Finance costse
Taxation credit (charge)f

Total after taxation

2014

2013

(6,576)
(60)
(100)
430
8

(6,298)

(1,190)
(133)
(165)
–
(82)

(1,570)

–
–
–
–
–

–

225
–
–
–
–

225

(304)
(180)
(176)
–
(10)

(670)

(781)

(9,094)
(38)
4,512

(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)

9,705
(39)
867

(4,620)

10,533

$ million

2012

3,638
(48)
–
347
(748)

3,189

(2,934)
(171)
(32)
–
(35)

(3,172)

(55)
(83)
–
–
384

246

–
–
–
–
–

–

(282)
(261)
(15)
–
(240)

(798)

(4,995)

(5,530)
(19)
251

(5,298)

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a See Financial statements – Note 3 for further information on impairments.
b 2014 included a $395-million write-off relating to Block KG D6 in India. 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.

c 2012 included dividend income from TNK-BP of $709 million and a charge of $325 million to settle disputes with Alfa, Access and Renova.
d 2012 included charges of $244 million relating to our exit from the solar business.
e Finance costs relate to the Gulf of Mexico oil spill. See Financial statements – Note 2 for further details.
f From 2014, tax is based on statutory rates except for non-deductible or non-taxable items. For earlier periods tax for the Gulf of Mexico oil spill and certain impairment losses, disposal gains and fair

value gains and losses on embedded derivatives, 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). For dividends received from
TNK-BP in 2012, there is no tax arising. Non-operating items reported within the equity-accounted earnings of Rosneft and TNK-BP are reported net of income tax.

* Defined on page 252.

BP Annual Report and Form 20-F 2014

209

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
set out below. Further information on fair value accounting effects is provided on page 253.

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

2014

2013

$ million

2012

(160)
191

679
188

867

898

(341)

557

23
8

914
(47)

867

(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)

a Fair value accounting effects arise solely in the fuels business.
b From 2014, tax is calculated using statutory rates. For earlier periods tax is calculated using the group’s discrete quarterly effective tax rate (adjusted for certain non-operating items, equity-accounted

earnings and certain deferred tax adjustments relating to changes in UK taxation).

Reconciliation of non-GAAP information

Upstream
RC profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects

RC profit before interest and tax

Downstream
RC profit before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects

RC 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

Operating capital employed*

Upstream
Downstream

TNK-BP

Rosneft

Other businesses and corporate

Gulf of Mexico oil spill response
Consolidation adjustment - UPII*
Total operating capital employed
Liabilities for current and deferred taxation
Goodwill
Finance debt
Net assets

210

BP Annual Report and Form 20-F 2014

2014

2013

8,903
31

8,934

2,871
867

3,738

5,514
898

6,412

16,901
(244)

16,657

3,097
(178)

2,919

32,191
(422)

31,769

$ million

2012

22,625
(134)

22,491

3,291
(427)

2,864

20,330
(561)

19,769

$ million

2014

107,524
38,878

–

7,312

20,689

(7,986)

(31)
166,386
(12,758)
11,868
(52,854)
112,642

Liquidity and capital resources

Financial framework
We maintain our financial framework to support the pursuit of value
growth for shareholders, while ensuring a secure financial base. BP’s
objective over time is to grow sustainable free cash flow* through a
combination of material growth in underlying operating cash flow* and
a strong focus on capital discipline, providing a sound platform to grow
shareholder distributions. The priority is to grow dividend per share
progressively in accordance with the growth in sustainable underlying
operating cash flow from our businesses over time. Any surplus cash
over and above that required for capital investment and dividend
payments will be biased towards further shareholder distributions
through buybacks or other mechanisms.

In the near term, and reflecting the weaker oil price environment, the
focus is to manage the business through a period of low oil prices and
support the dividend, which remains a priority. We aim to achieve this
by completing the $10-billion divestment programme (announced in the
fourth quarter of 2013), re-sizing the cost base and re-setting capital
expenditure to $20 billion, from the previously advised level of
$24-26 billion.
We aim to operate within a gearing* range of 10-20% and maintain a
significant liquidity buffer. As well as uncertainties relating to current
lower oil prices, the group also faces uncertainties relating to the Gulf of
Mexico oil spill as explained in Financing the group’s activities below.

Dividends and other distributions to shareholders
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 increased by 43% to 10 cents per share paid in the fourth
quarter of 2014. The dividend level is reviewed by the board in the first
and third quarter of each year.

The total dividend paid in cash to BP shareholders in 2014 was
$5.9 billion (2013 $5.4 billion) with shareholders also having the option
to receive a scrip dividend. 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 initial buyback
programme completed during the third quarter of 2014. Further surplus
cash, beyond capital and dividend payments, was applied to additional
buybacks, such that total cash paid for share buybacks in 2014 was
$4.8 billion (2013 $5.5 billion). Details of share repurchases to satisfy
the requirements of certain employee share-based payment plans are
set out on page 250.

Financing the group’s activities
The group’s principal commodities, oil and gas, are 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 48
for further information on risks associated with prices and markets and
Financial statements – Note 27.

The group’s gross debt at 31 December 2014 amounted to $52.9 billion
(2013 $48.2 billion). Of the total gross debt, $6.9 billion is classified as
short term at the end of 2014 (2013 $7.4 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. See Financial statements –
Note 24 for more information on the short-term balance.

Standard & Poor’s Ratings Services changed BP’s long-term credit
rating to A (negative outlook) from A (positive outlook) and Moody’s
Investors Service rating changed to A2 (negative outlook) from
A2 (stable outlook) during 2014.

Net debt was $22.6 billion at the end of 2014 a reduction of $2.6 billion
from the 2013 year-end position of $25.2 billion. The ratio of net debt to
net debt plus equity* was 16.7% at the end of 2014 (2013 16.2%). See
Financial statements – Note 25 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 $29.8 billion at 31 December 2014 (2013
$22.5 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.

The group also has undrawn committed bank facilities of $7.4 billion
(see Financial statements – Note 27 for more information).

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.

The group’s sources of funding, its access to capital markets and
maintaining a strong cash position are described in Financial statements
– Note 23 and Note 27. Further information on the management of
liquidity risk and credit risk, and the maturity profile and fixed/floating
rate characteristics of the group’s debt are also provided in Financial
statements – Note 24 and Note 27.

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 48 and Financial
statements – Note 2 for further information.

Off-balance sheet arrangements
At 31 December 2014, the group’s share of third-party finance debt of
equity-accounted entities was $14.7 billion (2013 $17.0 billion). 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 2014 were $83 million (2013 $199 million)
in respect of liabilities of joint ventures* and associates* and $244
million (2013 $305 million) in respect of liabilities of other third parties.
Of these amounts, $64 million (2013 $115 million) of the joint ventures
and associates guarantees relate to borrowings and for other third-party
guarantees, $126 million (2013 $143 million) relate to guarantees of
borrowings. Details of operating lease commitments, which are not
recognized on the balance sheet, are shown in the table below and
provided in Financial statements – Note 26.

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Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2014 and the proportion of
that expenditure for which contracts have been placed.

Capital expenditure

Committed
of which is contracted

Total

2015

39,708
15,635

18,009
8,061

2016

9,591
3,441

2017

5,445
2,163

2018

3,483
1,423

2019

2,265
442

2020 and
thereafter

915
105

$ million

Payments due by period

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 2014, the group had committed to capital expenditure relating to investments in equity-accounted entities amounting to
$2,068 million. Contracts were in place for $2,025 million of this total.

The following table summarizes the group’s principal contractual obligations at 31 December 2014, 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 24 and more information on operating leases is given in Financial statements – Note 26.

$ million

Payments due by period

Expected payments by period under contractual obligations

Total

2015

2016

2017

2018

2019

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

56,161
1,722
21,591
2,908
27,282

7,653
116
1,076
935
1,880

6,981
106
896
349
1,871

109,664

11,660

10,203

6,220
104
689
603
1,864

9,480

5,702
102
813
208
1,858

8,683

6,437
98
733
178
2,099

9,545

18,785
166,250

185,035

5,401
69,805

75,206

4,047
19,164

23,211

2,682
12,193

14,875

1,857
10,703

12,560

1,330
9,442

10,772

2020 and
thereafter

23,168
1,196
17,384
635
17,710

60,093

3,468
44,943

48,411

Total

294,699

86,866

33,414

24,355

21,243

20,317

108,504

a Expected payments include interest totalling $4,090 million ($822 million in 2015, $711 million in 2016, $610 million in 2017, $519 million in 2018, $424 million in 2019 and $1,004 million thereafter).
b Expected payments include interest totalling $939 million ($70 million in 2015, $65 million in 2016, $62 million in 2017, $59 million in 2018, $55 million in 2019 and $628 million thereafter).
c The amounts are undiscounted. Environmental liabilities include those relating to the Gulf of Mexico oil spill.
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 (such as fixed or minimum purchase volumes, timing of purchase
and pricing provisions). Agreements that do not specify all significant terms, or that are not enforceable, are excluded. 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 2015 include purchase commitments existing at 31 December 2014 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 27.

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

$ million

Payments due by period

Total

2015

78,063
29,982
12,836
3,610
731
21,799
19,229

43,714
17,741
3,097
2,425
219
1,423
1,186

2016

9,723
4,245
2,508
759
167
1,013
749

2017

5,418
2,552
2,145
262
108
1,062
646

2018

4,725
2,090
2,192
74
97
1,064
461

2019

3,530
1,604
2,228
28
50
926
1,076

2020 and
thereafter

10,953
1,750
666
62
90
16,311
15,111

166,250

69,805

19,164

12,193

10,703

9,442

44,943

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 241 and Risk factors on page 48, 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.

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Upstream analysis by region
Our upstream operations are listed by geographical area, with associated
significant events for 2014. BP’s percentage working interest in oil and
gas assets is shown in parenthesis. 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 20% 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. In September, BP and Tokyo Electric Power
Company (TEPCO) signed an agreement for TEPCO to purchase up to
1.2 million tonnes of LNG per year from BP for 17 years starting in 2017.

Europe
BP is active in the North Sea and the Norwegian Sea. Our activities focus
on maximizing recovery from existing producing fields and selected new
field developments. BP’s production is generated from three key areas;
the Shetland Area comprising Magnus, Clair, Foinaven and Schiehallion
fields; the Central Area comprising Bruce, Andrew and ETAP fields; and
Norway, comprising Valhall, Ula and Skarv fields.

• In March 2013 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 (BP 28.6%), west of
the Shetland Islands. By the end of 2014, five of the planned six appraisal
wells had been completed, with drilling started on the sixth well.

• Activity continued on the major redevelopment of the Schiehallion and
Loyal fields to the west of Shetland during 2014. Following work to
preserve the existing wells and subsea infrastructure, the risers and
moorings were disconnected, allowing the Schiehallion floating
production storage and offloading unit (FPSO) to be towed off-station in
May. Construction continues on the replacement FPSO, the Glen Lyon.

• Operations at the Rhum gas field recommenced in October under a

temporary management scheme announced by the UK government in
2013. Production had 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. See International trade sanctions on page 238.
• BP announced the Vorlich discovery in the central North Sea in

October. It spans the GDF SUEZ E&P UK Ltd-operated block 30/1f and
the BP-operated (BP 50%) block 30/1c.

• Production started up from the Kinnoull field (BP 77.06%) in the central
North Sea in December. The Kinnoull reservoir, developed as part of a
wider rejuvenation of the Andrew field area, is tied back to BP’s
Andrew platform and will enable production there to be extended. BP
has been granted three licences in the UK government’s 28th licensing
round. The licences are located in three of our core areas: to the north
of our Magnus field in the northern North Sea; next to our recent
Vorlich discovery; and west of our Kinnoull development. The
government is still to award some licences in this round as they are
undergoing environmental assessment.

• In December, a number of North Sea fields were subject to impairment

charges, primarily as a result of reductions in proved reserves,
decreases in short-term oil and gas price assumptions and increases in
expected decommissioning cost estimates. The total impairment
charge for 2014 was $4,774 million, of which $1,964 million related to
the Valhall asset, $660 million related to the Andrew area assets, and
$515 million related to the ETAP asset. There were a number of other
impairment charges that were not individually significant.

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 around 80 fields in the
central North Sea. The system has a capacity of more than 675mboe/d,
with average throughput in 2014 of 363mboe/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 providing transport and processing services. The pipeline has a
transportation capacity of 293mboe/d to a natural gas terminal at
Teesside in north-east England. Average throughput in 2014 was
134mboe/d. BP also operates the Sullom Voe oil and gas terminal in
Shetland. In December, BP announced the intent to sell our equity in the
CATS business.
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 36.
BP has around 600 lease blocks in the deepwater Gulf of Mexico, more
than any other company, and operates four production hubs.
• BP had 10 rigs in the Gulf of Mexico at the end of 2014.
• The BP-operated Na Kika Phase 3 project (BP 50%) and the Shell-

operated Mars B major project (BP 28.5%) started up in February. A
second Na Kika Phase 3 well started up in April.

• The Atlantis North expansion Phase 2 major project (BP 56%) started

up in April.

• BP announced an oil discovery at the Guadalupe prospect (BP 42.5%)
in the deepwater Gulf of Mexico in October. Project operator Chevron
drilled the discovery well on Keathley Canyon block 10 on behalf of the
Guadalupe co-owners. The well encountered significant economically
producible hydrocarbons in Paleogene age Wilcox Sands.

• In January 2015 BP announced it had formed a new ownership and

operating model with Chevron and ConocoPhillips to focus on moving
two significant BP Paleogene discoveries closer to development and
provide expanded exploration access in the deepwater Gulf of Mexico.
BP sold approximately half of its current equity interests in the Gila
field to Chevron in December and sold approximately half of its equity
interest in the Tiber field in January 2015. BP, Chevron and
ConocoPhillips also have agreed to joint ownership interests in
exploration blocks east of Gila known as Gibson, where they plan to
drill in 2015. As a result of the agreements, BP, Chevron and
ConocoPhillips will have the same working interests across Gila and
Gibson and any future centralized production facility. Chevron will hold
equity interest of 36%, BP 34% and ConocoPhillips 30%. In Tiber, BP
and Chevron will each hold equity interest of 31%, Petrobras 20% and
ConocoPhillips 18%. Chevron will operate Tiber, Gila and Gibson.
Operatorship is expected to be transferred after BP finishes drilling
appraisal wells at Gila and Tiber. BP believes combining the technical
strengths and financial resources of these three companies will provide
greater efficiency through scale, reduce subsurface risk and increase
the likelihood of achieving a future commercial development.

• BP was the apparent high bidder in 27 out of 32 blocks in the Gulf of

Mexico western lease sales in August, all of which have been
awarded. This is in addition to 24 blocks awarded in the Gulf of Mexico
in March lease sales. See also Significant estimate or judgement: oil
and natural gas accounting on page 102 for further information on
leases.

The US Lower 48 onshore business has significant activities producing
natural gas, NGLs and condensate across seven states, including
production from unconventional gas, coalbed methane (CBM) and shale
gas assets.
BP has an extensive resource base across 3.0 million net (5.5 million
gross) developed acres and over 22,815 gross wells, with daily
production around 300mboe/d. We believe there is potential to unlock
significant value from this resource base and we have decades of
experience in the necessary technologies.
Starting in 2015 our US Lower 48 onshore business began operating as a
separate business, with its own governance, processes and systems.
This is designed to promote faster decision making and adoption of
innovation so that BP can be more competitive in the US onshore
market. David Lawler was named chief executive officer in August.

BP Annual Report and Form 20-F 2014

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• BP and Pantera Acquisition Group, LLC (Pantera) signed an

agreement under which Pantera agreed to acquire BP’s interests in
the Panhandle West and Texas Hugoton gas fields for a purchase
price of $390 million in June. See page 26 for more information.
• Following on from the decision to create a separate BP business
around our US Lower 48 onshore oil and gas activities, and as a
consequence of disappointing appraisal results, we decided not to
proceed with development plans in the Utica shale, incurring a
$544-million write-off relating to this acreage.

For further information on the use of hydraulic fracturing in our shale gas
assets see page 43. BP’s onshore US crude oil and product pipelines and
related transportation assets are included in the Downstream segment.

In Alaska, at the end of 2014, BP operated nine North Slope oilfields in
the Greater Prudhoe Bay area and owned significant interests in six
producing fields operated by others. BP also owns significant non-
operating interests in the Point Thomson development project and the
Liberty prospect.

• In April BP announced the agreement to sell interests in four BP-

operated oilfields on the North Slope of Alaska to Hilcorp. The sale
agreement included all of BP’s interests in the Endicott and
Northstar oilfields and a 50% interest in each of the Milne Point
field and the Liberty prospect, together with BP’s interests in the
oil and gas pipelines associated with these fields. The sales price
was $1.25 billion plus an additional carry of up to $250 million if the
Liberty field is developed. The sale completed in November. See
page 26 for more information.

• Development of the Point Thomson initial production facility continued
throughout 2014. Engineering design is complete and construction of
field infrastructure and fabrication of the four main process modules is
in progress. Overall, the project is on track to commence production in
2016. BP holds a 32% working interest in the field, and ExxonMobil is
the operator.

• BP continued to work jointly with ExxonMobil, ConocoPhillips,

TransCanada, the Alaska Gasline Development Corporation and the
State of Alaska throughout 2014 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 (up to 20 million tonnes
per annum). In October 2013 selection of the lead site for the
liquefaction facility was announced as Nikiski, Alaska, located on the
south-central Alaskan coast. In January BP, ExxonMobil, ConocoPhillips
and TransCanada, and the Alaska Gasline Development Corporation
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, and provided a roadmap for State of Alaska participation in
the project. In April the Alaska Legislature passed legislation (SB-138)
which approved State participation in the project as a 25% co-investor,
and allowed payment of gas production tax in the form of gas volumes.
On 30 June 2014 the Alaska LNG co-venturers, including the State of
Alaska, executed commercial agreements and launched the pre-front
end engineering and design (pre-FEED) phase of the project, which is
expected to extend into 2016 with gross spend more than $500
million. A decision point for progressing to front end engineering and
design (FEED) phase of the project will be considered at the
completion of the pre-FEED phase. In July the Alaska LNG project
submitted an export application with the US Department of Energy,
and in September submitted a pre-file notice of application with the
Federal Energy Regulatory Commission (FERC), which was approved
by the FERC later that month. The US Department of Energy issued a
Free Trade Agreement Export Authorization to the project in
November. First commercial gas is planned between 2023 and 2025.

BP owns a 49% 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 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

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have not yet reached agreement regarding the terms for the transfer of
Unocal’s interest in TAPS and related litigation will continue in 2015.

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 offshore exploration interests in the Canadian Beaufort
Sea and in Nova Scotia.

• Phase 1 of the Sunrise Oil Sands SAGD development, in which BP has
a 50% non-operated interest, achieved first steam in the reservoir in
December 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 licenses was
conducted over the summer of 2014 with 7,090km2 of wide azimuth 3D
seismic data acquired. The processing of this seismic data will be
completed by the end of 2015 to identify possible exploration well
locations. During the fourth quarter of 2014 BP expanded the Nova
Scotia licence participation to include Hess Canada Oil and Gas ULC and
Woodside Energy International (Canada). The new participating interests
are BP 40% (operator), Hess 40% and Woodside 20%.

South America
BP has upstream activities in Brazil, Argentina, Bolivia, Chile, Uruguay
and Trinidad & Tobago.

In Brazil, BP has interests in 22 exploration and production concessions
across six basins, five of which are operated by BP. BP’s entry into five of
these concessions is subject to government and regulatory approvals.

• BP completed the sale of interest in the Polvo oil field (BP 60%) in

Brazil to HRT Oil & Gas Ltda for $135 million in January.

• During the year BP continued appraisal of the Itaipu discovery, located
in the deepwater sector of the Campos basin offshore Brazil, in line
with the appraisal plan approved by the Brazilian National Petroleum
Agency (ANP).

• In October the ANP approved the appraisal plan submitted by the

operator, Petróleo Brasileiro S.A. (Petrobras) for BM-POT-16 and BM-
POT-17 (two blocks in the deepwater Potiguar basin located in the
Brazilian equatorial margin), covering activities to 2018. BP’s farm-in to
a 40% interest in the blocks announced in July 2013 is subject to final
regulatory approvals.

• In July BP had a discovery at Xerelete (BP 18%) in Brazil’s Campos

basin, operated by Total.

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 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. BP holds a
100% interest in the blocks and the Uruguayan state oil company,
ANCAP, has a right to participate in up to 30% of any discoveries. BP has
already completed its commitment to acquire over 13,000km2 of 3D
seismic data and 3,000km of 2D seismic data by December 2015.

In Trinidad & Tobago, BP holds licences and production-sharing contracts
covering 1.8 million acres offshore of the east and north-east coast. Facilities
include 13 offshore platforms and two onshore processing facilities.
Production is comprised of gas and associated liquids. In August, the Juniper
project was sanctioned and subsequently a key contract for the
development of the project was awarded. Fabrication began in November.

BP also has a shareholding in Atlantic LNG (ALNG), an LNG liquefication
plant that averages 39% across four LNG trainsa with a combined
capacity of 15 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 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.

a An LNG train is a processing facility used to liquefy and purify natural gas in the formation of LNG.

Africa
BP’s upstream activities in Africa are located in Angola, Algeria, Libya,
Egypt and Morocco.

In Angola, BP is present in nine major deepwater licences offshore and is
operator in four of these. Two of these are in production (blocks 18 and
31), and two are in the exploration phase (blocks 19 and 24). The first
exploration well on block 24 (Katambi-1) is currently being drilled.

• Following a successful drill-stem test in May, BP had another oil and
gas discovery in the pre-salt play of Angola in block 20 (BP 30%)
operated by Cobalt International Energy, Inc. This discovery (the Orca-1
well) is the second pre-salt discovery in block 20. The Orca-2 appraisal
well is currently being drilled.

• Production commenced from the Total-operated CLOV (Cravo, Lirio,
Orquidea and Violeta) major project in Angola (BP 16.67%) in June.
Plateau production of 160,000 barrels of oil was achieved in September.
• In the first quarter the Angola LNG plant (BP 13.6%) produced and sold
a number of LNG cargoes, along with its first LPG, pressurised butane
and condensate cargoes. Following a technical incident in April 2014,
which caused an unplanned interruption to production, the plant’s
planned shutdown was brought forward to address both technical and
plant capacity issues. The plant is projected to re-start fully in 2016.

• In December, several fields in Angola were subject to impairment

charges, primarily as a result of changes in estimates of reserves and
resources and decreases in near-term oil price assumptions. The total
impairment charge during the year was $968 million, of which the
Plutão, Saturno, Vénus and Marte (PSVM) area was subject to an
impairment charge of $859 million.

In Algeria, BP, Sonatrach and Statoil are partners in the In Salah (BP
33.15%) and In Amenas (BP 45.89%) projects which supply gas to the
domestic and European markets. BP’s total assets in Algeria at
31 December 2014 were $1,717 million ($290 million current and
$1,427 million non-current).

• The security assessment following the terrorist attack in January 2013

has been completed.

• BP also had an appraisal and exploitation agreement with Sonatrach in
the Bourarhat Sud block, located to the south west of In Amenas. This
asset was in the exploration phase and was BP-operated. The
Bourarhat agreement with Sonatrach expired on 23 September 2014.
Sonatrach and BP were granted a six-month period to negotiate new
terms and those negotiations commenced in the fourth quarter. With
insufficient certainty of success, BP recorded an exploration write-off
of $524 million.

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 2014 were $515 million ($38 million current and
$477 million non-current).

BP served the National Oil Corporation with notices of force majeure on
17 August. This is the result of continued civil unrest in Libya, which has
made it impossible for BP to undertake its obligations under the EPSA
safely and securely. If the period of force majeure continues for two
years, the EPSA may terminate if the parties have failed to reach an
agreeable arrangement.

In Egypt, BP and its partners currently produce 10% of Egypt’s liquids
production and more than 30% of its gas production. BP’s total assets in
Egypt at 31 December 2014 were $7,715 million, of which $2,266 million
were current and $5,449 million were non-current. The current assets
include trade receivables and Egyptian pound denominated cash.

Egypt is moving forward towards the completion of the political roadmap
set out in June 2013. The government is committed to completing the
current transitional period and has already completed the first two
milestones, the adoption of the Constitution by a majority vote earlier this
year and the election of President Al Sisi in June. These are to be
followed by Parliament elections scheduled to take place through two
phases in March and April of 2015. Economic conditions remain

challenging despite the government’s clear focus on triggering economic
recovery and embarking on widescale national projects (such as the Suez
Canal). Egypt is also holding an Economic Summit in March with the
attendance of major foreign investors and with the government targeting
significant investments in projects across the various sectors. Another
key priority for the government is improving general security conditions
and combating extremist elements in North Sinai.

• We achieved first gas from the DEKA project offshore Egypt in August
with the start of production from the Denise South-6 well. The DEKA
project is centred on the Denise and Karawan gas fields in the Temsah
concession (BP 50%) in the East Nile.

• In September, we were awarded the El Matariya and Karawan

concessions in Egyptian Natural Gas Holding Company’s bid rounds
through partnering (50%) with Dana Gas and ENI respectively.
Karawan is located in the Mediterranean Sea in the northwestern part
of Egypt’s economic waters. El Mataria is an onshore block and BP is
an operator. BP and its partners have committed to invest a total of
$105 million in the blocks during the first phase.

• BP started drilling the Atoll-1 HPHT deepwater exploration well, the

second exploration well in the North Damietta offshore concession, in
September. Well performance is currently exceeding target pace and
drilling operations are expected to be completed in second half of 2015.
• West Nile Delta Project Concessions amendment was approved by the
Egyptian cabinet in December and will now proceed to the ratification
process in 2015.

In Morocco, BP has 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 the Agadir Basin, offshore
Morocco. The exploration periods run until 2017.

Asia
BP has activities in Western Indonesia, China, Azerbaijan, Oman, Abu
Dhabi, India and Iraq.

In Western Indonesia, BP participates in LNG exports through our 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 14% of the total gas feed to Bontang,
Indonesia’s largest LNG export facility and one of the world’s largest LNG
plants. It has a capacity of 22 million tonnes of LNG per annum and output of
more than 18 million tonnes.

In addition, BP participates in the Sanga-Sanga CBM PSA (BP 38%).
Another CBM PSA, Tanjung IV (BP 44%), in the Barito basin of Central
Kalimantan, will be relinquished pending the approval from the
government of Indonesia.

In China, during the year BP has exited blocks 42/05 (BP 40.82%), 43/11
(BP 40.82%) and 54/11 (BP 100%) in the South China Sea in accordance
with the PSAs and with government approvals. BP 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 supplied
under a long-term contract with Australia’s North West Shelf venture.

BP and the China National Offshore Oil Corporation (CNOOC) announced
a heads of agreement in June for the supply of up to 1.5 million tonnes of
LNG per year over 20 years starting in 2019.

In Azerbaijan, BP invests more than any other foreign investor, operates
two PSAs, Azeri-Chirag-Gunashli (ACG) (BP 35.8%) and Shah Deniz (BP
28.83%), 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. The Shah Deniz Stage 2 project (referred to
below) is also excluded from the EU and US sanctions. For further
information see International trade sanctions on page 238.

• The West Chirag platform came online in January, completing the

Chirag oil project (BP 35.8%), sanctioned in 2010.

* Defined on page 252. BP Annual Report and Form 20-F 2014

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• In March BP completed the purchase of an additional 3.33% equity in
Shah Deniz and the South Caucasus Pipeline (SCP) from Statoil for
$469 million.

• A ceremony to mark the groundbreaking for the Southern Gas Corridor

was held in September as part of the BP-operated Azerbaijan
International Operating Company celebration of the 20th anniversary of
the Azeri-Chirag-Gunashli production-sharing contract. This is a
milestone in the realization of the Shah Deniz Stage 2 project, which is
planned to deliver gas through the Southern Corridor comprising some
3,500 kilometres of pipeline to customers in Georgia, Turkey, Greece,
Bulgaria and Italy.

• In December BP and the State Oil Company of the Republic of
Azerbaijan signed a new PSA to jointly explore for and develop
potential prospects in the shallow water area around the Absheron
Peninsula in the Azerbaijan sector of the Caspian Sea.

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 2014 of 712mboe/d.

BP is technical operator of, and currently holds a 28.83% interest in, the
693-kilometre SCP. The pipeline takes gas from Azerbaijan through Georgia
to the Turkish border and has a capacity of 134mboe/d with average
throughput in 2014 of 111mboe/d. BP (as operator of Azerbaijan
International Operating Company) also operates the Western Export Route
Pipeline which transports ACG oil to the Black Sea coast of Georgia.

In Oman, BP currently has appraisal programmes and development
activities. In December 2013, BP and the Sultanate of Oman government
signed a gas sales agreement and an amended EPSA for the
development of the Khazzan field in block 61 with BP as operator.

• In February the Sultan of Oman issued a royal decree approving the

amended EPSA and the government acquired a 40% stake in block 61
through Makarim Gas Development LLC, a wholly owned subsidiary of
the state-owned Oman Oil Company Exploration & Production.

• In October we announced the award of two long-term drilling contracts
for the Oman Khazzan project in block 61. KCA Deutag was awarded
more than $400 million in contracts for the construction and operation
of five new build land rigs for Khazzan. Oman’s Abraj Energy Service
was awarded more than $330 million in contracts to supply three
drilling rigs for the full field development of the Khazzan project. Gas
production is expected to start in late 2017.

In Abu Dhabi, we had equity interests of 9.5% and 14.67% in onshore
and offshore concessions respectively in 2013. The Abu Dhabi onshore
concession expired in January 2014 with a consequent impact on
production of approximately 140mboe/d. BP participated in the tender
process for the new onshore concession.

We also have a 10% equity shareholding in the Abu Dhabi Gas
Liquefaction Company, which in 2014 supplied 5.9 million tonnes of LNG
(305.7bcfe regasified).

In India, BP has a 30% interest in four oil and gas PSAs operated by
Reliance Industries Limited (RIL), and is a partner with RIL in a 50:50 joint
operation for the sourcing and marketing of gas in India.

• During the year a number of activities continued to manage the

existing producing fields in the KG D6 block, with a focus on sustaining
production and extending the life of these fields. Activities included
well work-overs, side-tracks and new wells as well as progress on the
installation of additional compression capacity.

• In October the government of India announced new gas price

guidelines for domestic gas, effective 1 November 2014. The new
guidelines replace the earlier guidelines issued by the government in
January 2014.

• During the year we recorded an $810-million charge (comprising a

$415 million impairment charge and $395 million exploration write-off)
to write down the value ascribed to block KG D6 in India as part of the
acquisition of upstream interests from RIL in 2011. The charge arises
as a result of uncertainty in the future long-term gas price outlook,
following the introduction of a new formula for Indian gas prices,
although we do see the commencement of a transition to market-
based pricing as a positive step. We expect further clarity

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on the new pricing policy and the premiums for future developments
to emerge in due course.

In Iraq, BP holds a 47.6% working interest and is the lead contractor in
the Rumaila technical service contract. Rumaila is one of the world’s
largest oil fields, comprising five producing reservoirs. BP’s total assets in
Iraq at 31 December 2014 were $1,606 million ($1,235 million current
and $371 million non-current).

In September we signed an amendment to the Rumaila contract terms,
which include, among other things, the increase of BP equity and a five-
year term extension until 2034. BP is also working with the government
of Iraq and North Oil Company on studies in support of the stabilization
and redevelopment of two producing reservoirs of the Kirkuk field.
Despite instability and sectarian violence in the north and west of the
country, BP operations are continuing in the south.

Australasia
We are active in Australia and Eastern Indonesia.

In Australia, BP is one of seven participants 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 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 of LNG per annum.

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’s Jansz-Io interest is in the reserves and wells which
will provide the initial feed gas to the Gorgon LNG plant scheduled to
commence production late 2015.

BP holds a 70% interest in four deepwater offshore exploration blocks in
the Ceduna Sub Basin. 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 participants in the Browse LNG venture (operated
by Woodside) and holds a 17% interest. Browse is currently in the pre-
FEED stage of an offshore floating LNG development and remains
subject to regulatory, joint operation and internal BP approvals.
• We accessed new acreage in the offshore Outer Canning basin in
Western Australia in September by farming in to two exploration
permits (BP 21%).

In Eastern Indonesia, BP operates the Tangguh 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. It has a total capacity of 7.6 million tonnes of
LNG per annum. Tangguh supplies LNG to customers in Indonesia,
China, South Korea, Mexico and Japan through a combination of long,
medium and short-term contracts. Plans for a third train remain on track.

In August BP announced that the government of Indonesia, through the
Ministry of Environment, approved the Tangguh expansion project
integrated environment and social impact assessment and issued the
project (BP 37.16%) an environmental permit. This was followed by the
award of dual onshore FEED to two separate consortia, announced in
October. In addition, BP and the Tangguh partners signed a long-term
LNG sales agreement with PT PLN (Persero), Indonesia’s state-owned
electricity company, to supply up to 1.5 million tonnes of LNG each year
from 2015 to 2033. Supply will initially be provided from Tangguh’s
existing LNG trains. The agreement commits 40% of annual production
from train 3 to the domestic market.

BP has 100% interests in two deepwater PSAs: West Aru I and II and
32% interest in the Chevron-operated West Papua I and Ill PSAs. These
PSAs will be relinquished pending approval from the government of
Indonesia.

Downstream plant capacity
The following table summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2014.

Fuels value chain

US North West
US East of Rockies

Europe

Rhine

Iberia

Rest of world

Australia New Zealand

Southern Africa

Country

Refinery

Germany

Netherlands
Spain

Cherry Point
Whiting
Toledo

Bayernoilc
Gelsenkirchen
Karlsruhec
Lingen
Schwedtc
Rotterdam
Castellón

Australia

Bulwerd
Kwinana

New Zealand Whangareic
South Africa

Durbanc

Total BP share of capacity at 31 December 2014

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.
d We announced that we will halt refining operations at Bulwer in 2015.

Crude distillation capacitiesa

Group interestb
(%)

BP share
thousand barrels
per day

100
100
50

22.5
50
12
100
18.8
100
100

100
100
23.7
50

234
430
80

744

49
132
39
95
45
377
110

847

102
146
28
90

366

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Petrochemicals production capacitya
The following table summarizes BP group’s share of petrochemicals production capacities as at 31 December 2014.

Geographical area

Europe

UK
Belgium
Germany

Rest of world

Trinidad & Tobago
China

Indonesia
South Korea
Malaysia
Taiwan

Total BP share of capacity at 31 December 2014

BP share of capacity
thousand tonnes per annumb

Site

Group interest
(%)c

PTA

Acetic
acid

Olefins and
derivatives

Cooper River
Decaturd
Texas City

Hull
Geel
Gelsenkirchenf
Mülheimf

Point Lisas
Caojing
Chongqing
Nanjing
Zhuhaih
Merak
Ulsan
Kertih
Kaohsiung
Mai Liao
Taichung

100.0
100.0
100.0

100.0
100.0
50-61.0
50.0

36.9
50.0
51.0
50.0
85.0
100.0
51.0
70.0
61.4
50.0
61.4

1,300
1,000
–

2,300

–
1,300
–
–

1,300

–
–
–
–
1,800
500
–
–
300
–
500

3,100

6,700

–
700
1,300

2,000

–
700
–
–

700

–
–
–
–
–
–
–
–
–
–
–

–

2,700

–
–
600e

600

500
–
–
–

500

–
–
200
300
–
–
300
400
–
200
–

1,400

2,500

–
–
–

–

–
–
1,800g
–

1,800

–
3,300
–
–
–
–
–
–
–
–
–

3,300

5,100

Product

Others

–
–
100

100

200
–
–
100

300

700
–
100
–
–
–
100
–
–
–
–

900

1,300

18,300

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 Capacities are shown to the nearest hundred thousand tonnes per annum.
c Includes BP share of equity-accounted entities, as indicated.
d This site has 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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Oil and gas disclosures for the group

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 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 non-proved reserves or contingent resources.

Non-proved reserves and 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 volumes 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 2014 BP had material volumes of proved undeveloped
reserves held for more than five years in Trinidad, the North Sea and the
Gulf of Mexico. These are part of ongoing infrastructure-led 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 2014 we progressed 1,031mmboe of proved undeveloped reserves
(483mmboe 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
$18,704 million in 2014 ($15,096 million for subsidiaries and $3,608
million for equity-accounted entities). The major areas with progressed
volumes in 2014 were Angola, Azerbaijan, Russia, Trinidad, UK and 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 our proved undeveloped

Subsidiaries and equity-accounted entities

volumes in mmboea

Proved undeveloped reserves at 1 January 2014
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 2014

8,080
371
196
146
42
(15)

8,819
(1,031)

7,788

Subsidiaries only

volumes in mmboea

Proved undeveloped reserves at 1 January 2014
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 2014

4,844
(183)
180
123
42
(15)

4,990
(483)

4,507

a Because of rounding, some totals may not agree exactly with the sum of their component parts.

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
cases BP uses numerical simulation as part of a holistic assessment of
recovery factor for its fields, where these simulations 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. 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

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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
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 10 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 and of the American
Association of Petroleum Geologists Committee on Resource Evaluation
and is the current chair of the bureau of the United Nations Economic
Commission for Europe Expert Group on Resource Classification.

No specific portion of compensation bonuses for 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 2014, 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
2014. 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 its Annual Report on Form 20-F filed with the SEC.

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

220

BP Annual Report and Form 20-F 2014

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
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-four per cent of our total proved reserves of subsidiaries at
31 December 2014 were held through joint operations (83% in 2013),
and 33% of the proved reserves were held through such joint operations
where we were not the operator (31% in 2013).

Estimated net proved reserves of crude oil at 31 December 2014a 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

159
95
1,030
9
10
317
384
40

2,043
3,405

5,448

329
22
664
163
22
120
197
19

1,538
2,258

3,796

million barrels

Total

488
117
1,694
172
32
437
581
59

3,582
5,663

9,244

Estimated net proved reserves of natural gas liquids at 31 December 2014a b

million barrels

UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia

Subsidiaries
Equity-accounted entities

Total

Developed

Undeveloped

6
13
323
–
11
5
–
6

364
46

410

3
1
104
–
28
7
–
3

146
16

163

Total

9
14
427
–
39
12
–
10

510
62

572

Estimated net proved reserves of liquids*

Subsidiaries
Equity-accounted entities

Total

Developed

Undeveloped

2,407
3,451

5,858

1,684
2,274

3,958

million barrels

Total

4,092d e
5,725f

9,817

Estimated net proved reserves of natural gas at 31 December 2014a 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

382
300
7,168
17
2,352
901
1,688
3,316
16,124
6,363
22,487

386
19
2,447
–
6,313
1,597
3,892
1,719
16,372
5,837
22,209

768
318
9,615
17
8,666
2,497
5,580
5,035
32,496g
12,200h
44,695

The Abu Dhabi onshore concession expired in January 2014 with a
consequent reduction in production of approximately 140mboe/d. Our
Abu Dhabi offshore concession is due to expire in 2018. 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 174.

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Estimated net proved reserves on an oil equivalent basis

Subsidiaries
Equity-accounted entities

Total

million barrels of oil equivalent

Developed

Undeveloped

5,187
4,548

9,735

4,507
3,280

7,788

Total

9,694
7,828

17,523

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 2014 marker prices used were Brent $101.27/bbl (2013 $108.02/bbl and 2012

$111.13/bbl) and Henry Hub $4.31/mmBtu (2013 $3.66/mmBtu and 2012 $2.75/mmBtu).

c Includes condensate and bitumen.
d Proved reserves in the Prudhoe Bay field in Alaska include an estimated 65 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 liquids in respect of the 30% non-controlling interest in BP

Trinidad and Tobago LLC.

f Includes 38 million barrels of crude oil in respect of the 0.16% non-controlling interest in

Rosneft held assets in Russia.

g Includes 2,519 billion cubic feet of natural gas in respect of the 30% non-controlling interest in

BP Trinidad and Tobago LLC.

h Includes 91 billion cubic feet of natural gas in respect of the 0.18% non-controlling interest in

Rosneft held assets in Russia.

Because of rounding, some totals may not agree exactly with the sum
of their component parts.

Proved reserves replacement
Total hydrocarbon proved reserves at 31 December 2014, on an oil
equivalent basis including equity-accounted entities, decreased by 3%
(decrease of 5% for subsidiaries and increase of 1% for equity-
accounted entities) compared with 31 December 2013. Natural gas
represented about 44% (58% for subsidiaries and 27% for equity-
accounted entities) of these reserves. The change includes a net
decrease from acquisitions and disposals of 39mmboe (all within our
subsidiaries). Acquisition activity in our subsidiaries occurred in
Azerbaijan, the US and the UK, and divestment activity in our
subsidiaries in the US and Brazil.

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 2014, the proved reserves replacement ratio excluding
acquisitions and disposals was 63% (129% in 2013 and 77% in 2012)
for subsidiaries and equity-accounted entities, 29% for subsidiaries
alone and 116% for equity-accounted entities alone. The decreased
ratio reflected lower reserves bookings as a result of fewer final
investment decisions in 2014 and revisions of previous estimates.

In 2014 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted to
743mmboe (208mmboe for subsidiaries and 535mmboe 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 2014
principally resulted from the application of conventional technologies.
The principal proved reserves additions in our subsidiaries were in
Angola, Azerbaijan, Iraq, Oman, Trinidad and the US. We had material
reductions in our proved reserves in Norway, the UK, Indonesia and
Australia, principally due to activity reduction and reservoir performance.
The principal reserves additions in our equity-accounted entities were in
Argentina and Russia.

Sixteen per cent of our proved reserves are associated with PSAs. The
countries in which we operated under PSAs in 2014 were Algeria,
Angola, Azerbaijan, Egypt, India, Indonesia, Oman and a non-material
volume of our proved reserves in Trinidad. In addition, the technical
service contract (TSC) governing our investment in the Rumaila field in
Iraq functions as a PSA.

* Defined on page 252. BP Annual Report and Form 20-F 2014

221

BP’s net production by country – crude oila and natural gas liquids

Subsidiaries
UKc d

Norwayc

Total Rest of Europe

Total Europe

Alaskac

Lower 48 onshorec

Gulf of Mexico deepwaterc

Total US

Canadac

Total Rest of North America

Total North America

Trinidad & Tobago
Brazilc

Total South America

Angola

Egypt

Algeria

Total Africa

Azerbaijanc

Western Indonesia

Iraq

Other

Total Rest of Asia

Total Asia

Australia

Other

Total Australasia

Total subsidiariese

Equity-accounted entities (BP share)

TNK-BP (Russia, Venezuela, Vietnam)c f

Rosneft (Russia, Canada, Venezuela, Vietnam)c g

Abu Dhabih
Argentina
Bolivia
Egypt
Other

2014

2013

Crude oil
2012

127

206

347

–

137

156

305

–

103

139

176

327

–

347

305

327

13
–

181

222

156

10
7

180

217

141

8
7

149

191

137

thousand barrels per day

BP net share of productionb

2014

2013

Natural gas
liquids
2012

–

12
–

–

12
–

–

13
–

–

–
3
–
5
–

844

789

795

–

816

97
62
3
–
1

183

643

231
60
2
–
1

857

–

216
63
1
–
1

–

–
3
–
4
–

–
3
–
5
–

Total equity-accounted entities

Total subsidiaries and equity-accounted entities

979

1,120

1,137

1,823

1,909

1,932

104

105

123

a Includes condensate.
b 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.

c In 2014, BP divested its interests in the Endicott and Northstar fields, and 50% of its interests in the Milne Point field, in Alaska, its interest in the US onshore Hugoton upstream operation and its
interest in the Polvo asset in Brazil. BP also reduced its interest in certain wells in the US onshore Eagle Ford Shale in south Texas. It increased its interest in the Shah Deniz asset in Azerbaijan, in
certain UK North Sea assets, and in certain US onshore assets. 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.

d Volumes relate to six BP-operated fields within ETAP. BP has no interests in the remaining three ETAP fields, which are operated by Shell.
e Includes 7 net mboe/d of NGLs from processing plants in which BP has an interest (2013 5.5mboe/d and 2012 13.5mboe/d).
f 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.
g 2014 is based on preliminary operational results of Rosneft for the three months ended 31 December 2014. Actual results may differ from these amounts. 2013 reflects production for the period

21 March to 31 December, averaged over the full year.

h BP holds interests, through associates, in offshore concessions in Abu Dhabi which expire in 2018. We similarly held onshore concessions which expired in 2014.

Because of rounding, some totals may not agree exactly with the sum of their component parts.

222

BP Annual Report and Form 20-F 2014

BP’s net production by country – natural gas

Subsidiaries
UKb

Norway

Total Rest of Europe

Total Europe

Lower 48 onshoreb

Gulf of Mexico deepwaterb

Alaska

Total US

Canada

Total Rest of North America

Total North America

Trinidad & Tobago

Total South America

Egypt

Algeria

Total Africa

Azerbaijanb
Western Indonesia

India

Otherb

Total Rest of Asia

Total Asia

Australia

Eastern Indonesia

Total Australasia

Total subsidiariesc

Equity-accounted entities (BP share)

TNK-BP (Russia, Venezuela, Vietnam)b d

Rosneft (Russia, Canada, Venezuela, Vietnam)b e

Argentina
Bolivia
Other

Total equity-accounted entitiesc

Total subsidiaries and equity-accounted entities

million cubic feet per day

BP net share of productiona

2014

2013

2012

102

173

157

237

414

422

1,350

1,404

1,499

159

114

134

1,519

1,539

1,651

1,529

1,551

1,664

2,147

2,221

2,097

406

107

513

230
47

131

–

408

450

364

814

444

117

561

203
51

156

490

431

353

784

470

120

590

158
59

313

103

633

435

352

787

5,585

5,845

6,193

–

1,084

323
80
28

1,515

7,100

184

617

329
55
30

785

–

355
34
26

1,216

1,200

7,060

7,393

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 2014, BP divested its interest in the US onshore Hugoton upstream operation. BP also reduced its interest in certain wells in the US onshore Eagle Ford Shale in south Texas. It increased its interest

in the Shah Deniz asset in Azerbaijan, in certain UK North Sea assets, and in certain US onshore assets. 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.

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 2014 is based on preliminary operational results of Rosneft for the three months ended 31 December 2014. Actual results may differ from these amounts. 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.

BP Annual Report and Form 20-F 2014

223

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The following tables provide additional data and disclosures in relation to our oil and gas operations.

Average sales price per unit of productiona

$ per unit of production

Subsidiaries

2014

Crude oilc
Natural gas liquids
Gas

2013

Crude oilc
Natural gas liquids
Gas

2012

Crude oilc
Natural gas liquids
Gas

Equity-accounted entitiesd

2014

Crude oilc
Natural gas liquids
Gas

2013

Crude oilc
Natural gas liquids
Gas

2012

Crude oilc
Natural gas liquids
Gas

Europe

Rest of
Europe

North
America

Rest of
North
America

South
America

Africa

Asia

Australasia

Russiab

Rest of
Asia

96.02
58.11
8.13

97.77
52.97
8.22

93.66
32.28
3.80

107.83
62.53
9.43

107.78
61.82
10.18

102.07
30.95
3.07

111.76
74.38
8.62

109.07
60.36
9.43

107.55
34.65
2.32

–
–
–

96.85
41.62
4.65

93.99
53.67
5.92

106.37
54.92
4.66

107.02
69.39
5.75

105.83
52.46
3.53

110.08
75.82
6.05

–
–
–

73.87
15.75
4.73

74.01
29.63
4.05

81.32
22.36
2.35

–
–
–

84.19
n/a
2.18

95.28
n/a
2.47

86.76
7.63
2.35

91.05
–
6.28

108.26
–
4.99

109.74
–
5.08

14.70
–
12.83

11.58
–
13.21

10.15
–
5.08

94.04
65.70
11.20

105.89
68.13
10.55

106.47
84.96
10.08

–
–
–

Total
group
average

93.65
36.15
5.70

105.38
38.38
5.35

108.94
42.75
4.75

72.53
15.75
3.01

63.51
29.63
3.26

62.11
9.70
2.52

a Units of production are barrels for liquids and thousands of cubic feet for gas. Realizations include transfers between businesses, except in the case of Russia in 2014 and 2013.
b Amounts reported for Russia in 2014 and 2013 include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The operational and financial information of the

Rosneft segment for 2014 is based on preliminary operational and financial results of Rosneft for the three months ended 31 December 2014. Actual results may differ from these amounts. Crude oil
includes natural gas liquids in 2014 and 2013.

c Includes condensate.
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

2014
2013
2012

Equity-accounted entities

2014
2013
2012

$ per unit of production

Europe

Rest of
Europe

North
America

South
America

Rest of
North
America

Africa

Asia

Australasia

Russiab

Rest of
Asia

44.67
34.10
22.77

18.85
24.48
39.10

14.22
16.11
15.60

–
–
–

5.43
5.92
5.69

11.28
12.16
11.33

13.37
13.84
11.89

–
–
–

15.55
13.20
11.85

–
–
–

3.82
4.36
5.72

4.34
4.19
2.88

3.92
3.21
3.23

–
–
–

Total
group
average

12.68
13.16
12.50

4.75
5.28
5.76

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 2014 and 2013 include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. The operational and financial information of the

Rosneft segment for 2014 is based on preliminary operational and financial results of Rosneft for the three months ended 31 December 2014. Actual results may differ from these amounts.

224

BP Annual Report and Form 20-F 2014

Environmental expenditure

Environmental expenditure relating to the

Gulf of Mexico oil spill

Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental remediation

2014

2013

190
624
590
33

(66)a
657
1,091
42

provision

Additions to decommissioning provision

371
2,216

472
2,092

$ million

2012

919
742
1,207
47

549
3,766

a The environmental expenditure credit of $66 million in 2013 arises primarily from the write-back

of a spill response provision.

Environmental expenditure relating to the Gulf of
Mexico oil spill
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 $624 million in 2014 was at a
similar level to 2013.

Capital expenditure in 2014 was lower than in 2013 principally due to
reduced levels of construction activity at our Whiting refinery in 2014 as
compared to 2013. The final major units associated with the Whiting
refinery modernization project were commissioned in December 2013.

Clean-up costs in 2014 were lower than in 2013 primarily due to an
overall reduction in clean-up activities and services required across sites.

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.

Provisions for environmental remediation are made when a clean-up is
probable and the amount of the obligation can be reliably estimated.
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 2014
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 2014 included $13 million in respect of
provisions for new sites (2013 $13 million and 2012 $19 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 2014 additions to the decommissioning provision were greater than in
2013, and occurred as a result of detailed reviews of expected future
costs, and to a lesser extent increases to the asset base. The majority of
these additions related to our sites in the North Sea, the Gulf of Mexico
and Angola. The additions in 2012 and 2013 were driven by changes in
estimation and detailed reviews of expected future costs.

In 2012 and 2013, 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’. Further details
of decommissioning and environmental provisions appear in the financial
statements – Note 21.

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, biofuels, wind and shipping activities, are conducted
in almost 80 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 some 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.

BP frequently 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

* Defined on page 252. BP Annual Report and Form 20-F 2014

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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) 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 it has 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 will typically 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 parties or other losses. The allocation of those risks vary among
contracts and are determined through negotiation between the parties.

In general, BP incurs income tax on income generated from production
activities (whether under a licence or PSA). 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
Current and proposed fuel and product specifications, emission controls,
climate change programmes and regulation of unconventional oil and 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.
See Financial Statements – Note 21 for information on provisions for
environmental restoration and remediation.

A number of pending or anticipated governmental proceedings against
certain BP group companies under environmental laws could result in
monetary or other sanctions. Group companies 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 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, such as stricter environmental laws or enforcement
policies, or future events at our facilities, on the group, 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 225.

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 operations. Significant legislation and regulation in the US and
the EU affecting our businesses and profitability includes the following:

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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. States may also 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
with our operations and can require corrective action at locations
where such wastes have been disposed of or released.

• 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 manufacture, import,

export, sale and use of chemical substances and 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

(GHS) for hazard classification and labelling of chemicals and products,
with the modification of the Occupational Safety & Health
Administration (OSHA) Hazard Communication Standard. This requires
BP to reassess the hazards of all our chemicals and products against
new GHS criteria as adopted or modified by OSHA and to update
warning labels and safety data sheets accordingly by 1 June 2015.
• 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
30 BP facilities.

• OPA 90 is implemented through regulations issued by the US

Environmental Protection Agency (EPA), the US Coast Guard, the DOT,
OSHA, 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 36). 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 2010 Deepwater Horizon oil spill, see Legal
proceedings on page 228.

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

• In October 2014, the European Council agreed on new climate and

energy targets for the period up to 2030.

• The 2008 EU Climate and Energy Package is expected to remain in
place until 2020 and includes an updated EU Emissions Trading
System (EU ETS) Directive and the Renewable Energy Directive. The
updated 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
sector benchmarks used to calculate the number of free emissions per
installation.

• 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, including mandatory industrial energy efficiency
surveys. This directive is being implemented in the UK by the Energy
Savings Opportunity Scheme (ESOS), which affects our offshore and
onshore assets. ISO50001 is being implemented in some EU states to
meet some elements of the Energy Efficiency Directive.

• The Industrial Emissions Directive (IED) provides the framework for
granting permits for major industrial sites. It lays down rules on
integrated prevention and control of air, water and soil pollution arising
from industrial activities. This may result in requirements for BP to
further reduce its emissions, particularly its air and water emissions. As
part of the IED framework, additional emission limit values are
informed by the sector specific and cross-sector Best Available
Technology (BAT) Conclusions, such as the recently published BAT
Conclusions for the refining sector. Further BAT Conclusions that may
result in additional emission reduction requirements are expected
within the next two years.

• The European Commission’s Clean Air Policy Package (including a new

directive for medium-sized combustion plants, a revised National
Emission Ceilings Directive and a ratification proposal for the amended
Gothenburg Protocol) may – once adopted wholly or in part – 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 freshwater withdrawals and discharges from its EU
operations.

• The EU regulation on ozone depleting substances (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 Montreal Protocol and related
legislation. In addition, the EU regulation on fluorinated gases with high
global warming potential came into force on 1 January 2015. This
might further limit the use of some refrigerants, such as in gas
processing facilities.

• 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, 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. In accordance with
the required phase-in timetable, BP has completed registration of all
substances in tonnage bands equal to or greater than 100 tonnes per
annum/legal entity, and is in the process of preparing registration
dossiers for substances manufactured or imported in amounts in the
range 1-100 tonnes per annum/legal entity that are currently 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 review for potential
authorization and restriction procedures, and possible banning, by the
European Chemicals Agency and EU member state authorities.
• In addition, the EU is implementing the UN Global Harmonization
System for hazard classification and labelling of chemicals and
products through the Classification Labelling and Packaging (CLP)
Regulation. This requires BP to reassess the hazards of all our

chemicals and products against the new GHS criteria as adopted or
modified by the EU and to update warning labels and safety data
sheets accordingly. The CLP will come into effect for mixtures (e.g.
lubricants) in 2015. A separate EU regulation on export and import of
hazardous chemicals requires warning labels and safety data sheets
accompanying EU exports to be compliant with relevant CLP and
REACH requirements (unless this conflicts with requirements in the
importing country) and, as far as practicable, in the official or one or
more principal languages of the intended area of use. Safety data
sheets for the EU market have been or are being updated to include
both REACH and CLP information.

• The EU Offshore Safety Directive, adopted in 2013, is required to be
transposed into national legislation by Member States, including the
UK, by 19 July 2015. 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. As of 6 January 2015, the number of contracting states to
the HNS Convention remained at 14, so it has not yet entered
into force.

• Changes to the permitted level of sulphur in marine fuels under EU

mandated reductions and International Maritime Organization
guidelines over the next 5-10 years are intended to result in the
reduction of sulphur oxides emissions from ships, either through the
burning of low sulphur marine fuels or the use of approved on-board
abatement technology. 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), although there can be no assurance
that a spill will necessarily be adequately covered by insurance or that
liabilities will not exceed insurance recoveries.

Greenhouse gas regulation
Increasing concerns about climate change have led to a number of
international climate agreements and negotiations that are ongoing.

In 2011, parties to the UN Framework Convention on Climate Change
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

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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 2014 conference (COP20) in Lima adopted the Lima Call for Climate
Action. This included the elements of a negotiating text for a new
international agreement, as specified in Durban in 2011, to be finalized at
COP21 in Paris in December 2015. This text covers long-term ambitions
and pathways and a framework for reaching it. COP20 also agreed on the
rules for providing and assessing information about each country’s
’Intended Nationally Determined Contributions (INDCs)’ towards reaching
the overall ambition. The world’s three largest emitters – China, the US
and the EU – have all announced their intentions to limit their 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 and announced measures and developments potentially
affecting BP’s businesses include the following:

• The 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 that includes: a collective national reduction target
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. EU energy efficiency
policy is currently implemented via national energy efficiency action
plans and the Energy Efficiency Directive adopted in 2012. The EU has
also recently agreed to the framework of the 2030 Climate and Energy
Policies with a goal of at least a 40% reduction in GHGs from 1990 and
measures to achieve a 27% share of renewable energy and a 27%
increase in energy efficiency. The GHG reduction target is to be
achieved by a 43% reduction of emissions from sectors covered by the
EU ETS, and a 30% GHG reduction by Member States for all other
GHG emissions.

• 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.

• Canada’s highest emitting province, Alberta, has regulations targeting
large final emitters (sites with over 100,000 tonnes CO2e/per annum)
with intensity targets of 2% improvement per year up to 12%.
Compliance is possible via direct reductions, the purchase of offsets or
the payment of C$15/tonne to a technology fund.

• In the US, the US Environmental Protection Agency (EPA) continues to
pursue regulatory measures to address GHGs under the Clean Air Act
(CAA).

– EPA regulations impose light duty vehicle emissions standards for
GHGs and permitting requirements for certain large GHG emission
sources.

– Under the GHG mandatory reporting rule (GHGMRR), annual
reports on GHG emissions must be filed. 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 proposed regulations establishing GHG emission limits
for new and modified power plants in September 2013. In June
2014, the EPA proposed a very complex ‘Clean Energy Plan’
Regulation that establishes GHG reduction requirements, at a
state or regional level, for existing power plants. The EPA
announced its intention to finalize both rules in or around June
2015. These rules are important due to potential impacts on
electricity prices, reliability of electricity supply, precedents for

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similar rules targeting other sectors and potential impacts on
combined heat and power installations.

• A number of additional state and regional initiatives in the US will affect
our operations. California implemented a low-carbon fuel standard in
2010. The California cap and trade programme started in January 2012
with the first auctions of carbon allowances held in November 2012
and obligations commencing from 2013. The California cap and trade
programme was broadened to include transport fuels on 1 January
2015.

• In the recent US-China joint announcement on climate change

addressing post-2020 actions, the US committed to reducing its GHG
emissions by 26-28% below its 2005 level by 2025. Achieving these
reductions will require expanded efforts to reduce emissions, which
likely will include regulatory measures. China announced it intends to
achieve a peak in CO2 emissions around 2030, with the intention to try
to peak earlier and to increase the non-fossil fuel share of all energy to
around 20% by 2030. Currently, China has targets to reduce carbon
intensity of GDP 40-45% below 2005 levels by 2020 and increase the
share of non-fossil fuels in total energy consumption from 7.5% in
2005 to 15% by 2020.

• China is operating emission trading pilots in five cities and two

provinces. A number of BP joint venture* companies in China are
participating in these schemes. The Chinese government is also
considering a plan for a national cap and trade system in 2016.

• South Africa has delayed implementation of a carbon tax on carbon

intensive emitters until 2016.

• South Korea commenced its carbon emissions trading scheme in

January 2015.

For information on the steps that BP is taking in relation to climate
change issues and for details of BP’s GHG reporting see Environment
and society on page 42.
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
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 3,000 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.

Many of the lawsuits pending in federal court have been consolidated by
the Federal Judicial Panel on Multidistrict 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).

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 US filed a civil complaint in MDL 2179 against BPXP and others on
15 December 2010 (the DoJ Action). The complaint seeks an order
finding 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.

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 (BPAPC) 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.

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.

Also 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.

Also 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 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 4 September 2014, as part of its findings of fact and
conclusions of law for Phase one of the Trial of Liability Limitation
Exoneration and Fault Allocation in MDL 2179 (Phase 1 Ruling), the court
ruled that Halliburton’s indemnity and release clauses in its contract with
BP are valid and enforceable against BP.

On 30 May 2011, Transocean filed claims against BP in the DoJ Action
alleging that BPAPC 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
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 is not required to indemnify Transocean 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 4 September 2014, as part of its Phase 1
Ruling, the court ruled that Transocean’s indemnity and release clauses
in its contract with BP are valid and enforceable against BP.

On 8 December 2011, the US 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

★ Defined on page 252.

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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 US, 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 US each appealed to the US Court of
Appeals for the Fifth Circuit (the Fifth Circuit), and on 4 June 2014 the
Fifth Circuit unanimously affirmed the district court’s decision. On 21 July
2014, Anadarko and BPXP filed petitions requesting that all active judges
of the Fifth Circuit review the 4 June 2014 decision. On 9 January 2015,
the Fifth Circuit issued an order denying the petition for rehearing, on a
7-6 vote. Absent an extension, BPXP’s deadline for seeking US Supreme
Court review is 9 April 2015.

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.

Also 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 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 Phase 1

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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. After the
completion of post-trial briefing, 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 PSC and Halliburton
also submitted briefs addressing the implications of Halliburton’s plea
agreement. On 4 September 2014 the court granted BP’s motion in part,
supplementing the Phase 1 trial record with the Halliburton plea
agreement, the US press release, and certain other documents related to
Halliburton’s criminal plea. The court also found that the simulations at
issue in Halliburton’s criminal plea, if not deleted by Halliburton
employees, would have indicated that using 6 centralizers, as opposed to
21, would not have caused cement channeling in the Macondo well and
that Halliburton’s deletion of the simulations was done intentionally and
in bad faith.

On 4 September 2014, the court issued its Phase 1 Ruling. The court
found that BPXP, BPAPC, Transocean Holdings LLC, Transocean
Deepwater Inc., Transocean Offshore Deepwater Drilling Inc.
(Transocean Entities), and Halliburton are each liable under general
maritime law for the blowout, explosion, and oil spill from the Macondo
well. The court found that the conduct of BPXP and BPAPC was reckless,
and it apportioned to them 67% of the fault for the blowout, explosion,
and oil spill. The court found that the conduct of the Transocean Entities
was negligent and apportioned to them 30% of the fault for the blowout,
explosion, and oil spill. The court found that Halliburton’s conduct was
negligent and apportioned to it 3% of the fault for the blowout, explosion,
and oil spill.

The district court ruled that under Fifth Circuit precedent BPXP and
BPAPC cannot be liable for punitive damages under general maritime
law, but to the extent the standards of the First Circuit or Ninth Circuit
Courts of Appeals would apply to a particular claim, the court found that
BPXP would be liable for punitive damages under those rules.

With respect to the US’ claims against BPXP under the Clean Water Act,
the district court found that the discharge of oil was the result of BPXP’s
gross negligence and wilful misconduct and that BPXP is therefore
subject to enhanced civil penalties. The court further found that BPXP
was an ‘operator’ and ‘person in charge’ of the Macondo well and the
Deepwater Horizon vessel for the purposes of the Clean Water Act.

The district court did not find BP p.l.c. to be at fault in connection with
the blowout, explosion, and oil spill, and it ruled that BP p.l.c., Transocean
Ltd., and Triton Asset Leasing GmbH are not liable under general
maritime law.

The district court ruled that Transocean Entities are not entitled to limit
liability under the Limitation of Liability Act and that they are liable to the
US for removal costs under OPA 90.

In addition, the district court ruled that the indemnity and release clauses
in BP’s contracts with Halliburton and Transocean Entities are valid and
enforceable against BP and granted BP’s motion to supplement the
Phase 1 trial record with 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.

On 2 October 2014, BPXP and BPAPC filed a motion with the district
court to amend the findings in the Phase 1 Ruling, to alter or amend the
judgment, or for a new trial on the grounds that the court’s allocation of
fault and findings of gross negligence and wilful misconduct relied upon
testimony which had been excluded from the evidence presented at the
Phase 1 trial and as to which BPXP and BPAPC did not have adequate
notice and opportunity to present evidence in rebuttal. The court denied
BPXP’s and BPAPC’s motion to amend to the Phase 1 Ruling on
13 November 2014. On 11 December 2014, BPXP and BPAPC filed a
notice of appeal of the Phase 1 Ruling to the Fifth Circuit, and
subsequently notices of appeal were also filed by the PSC, Transocean,
Halliburton and the State of Alabama.

Phase 2, which commenced on 30 September 2013, addressed
(1) ‘source control’ issues pertaining to the conduct or inaction of BP,
Transocean Entities 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 (2) ‘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. On 15 January 2015 the district court issued its
Findings of Fact and Conclusions of Law for Phase 2 of the Trial of
Liability, Limitation, Exoneration and Fault Allocation in MDL 2179, finding
that 3.19 million barrels of oil were discharged into the Gulf of Mexico
and therefore subject to a Clean Water Act penalty. In addition, the
district court found that BP was not grossly negligent in its source control
efforts. On 23 February 2015, BPXP filed a notice of appeal of the Phase
2 ruling to the Fifth Circuit.

In the penalty phase of the Trial of Liability, Limitation, Exoneration and
Fault Allocation in MDL 2179 the district court will determine the amount
of civil penalties to be assessed against BPXP and Anadarko arising under
the Clean Water Act based on the court’s application of the penalty
factors under the Clean Water Act. The penalty phase trial commenced
on 20 January 2015 and concluded on 2 February 2015. The court has
established a post-trial briefing schedule for the penalty phase under
which briefing is to be concluded on 24 April 2015. BP is not currently
aware of the timing of the district court’s ruling for the penalty phase.

The district court has wide discretion in 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 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 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. The deadline for submitting claims under

the Medical Benefits Class Action Settlement passed on 12 February
2015. 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 funded $79.1 million for
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
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 Deepwater Horizon Oil Spill Trust (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
2014, the aggregate cash balances in the Trust and the qualified
settlement funds amounted to $5.1 billion, including $1.1 billion
remaining in the Seafood Compensation Fund, from which a further
$0.5 billion partial distribution started in early 2015, and $0.4 billion held
for natural resource damage early restoration projects. When the cash
balances in the Trust are exhausted, 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. This provides that 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.
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. As a
result of 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.

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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
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 filed petitions
requesting that all the active judges of the Fifth Circuit review the
decision to uphold approval of the settlement. On 19 May 2014, BP’s en
banc petition to the full court was denied by a vote of 8-5. As explained in
further detail below, BP filed a certiorari petition with the US Supreme
Court on 1 August 2014, which was denied on 8 December 2014.

PSC settlements – Deepwater Horizon Court Supervized 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-supervized
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 2013 Ruling).

BP appealed the district court’s March 2013 Ruling and related rulings to
the Fifth Circuit. On 2 October 2013, the business economic loss panel of
the Fifth Circuit (by a 2-1 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 suspended payment to claimants
affected by the misinterpretation issue and who did 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 24 December 2013, the district court ruled on the two issues
remanded to it in October 2013 by the business economic loss panel of
the Fifth Circuit (the December 2013 Ruling): (1) requiring the claims
administrator, in administering business economic loss claims, to match

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revenue with corresponding variable expenses (the matching issue), and
(2) determining whether the settlement agreement can properly be
interpreted to permit payment to business economic loss claimants
whose losses (if any) were not caused by the spill (the causation issue).

As to the matching issue, the district court ordered the claims
administrator to develop a revised policy addressing the matching of
revenue and expenses for business economic loss claims, which would
require the matching of revenue with the expenses incurred by claimants
to generate that revenue, even where the revenue and expenses were
recorded at different times. On 13 March 2014, the claims administrator
issued a revised matching policy reflecting this order. On 5 May 2014,
the district court approved the revised policy. The PSC filed a motion on
27 May 2014 seeking to alter or amend the revised policy. On 27 June
2014, the district court issued an order establishing the process for the
parties and claims administrator to determine which already-determined
but unpaid claims should be subject to the revised policy.

As to the causation issue, the district court ruled that the Economic and
Property Damages Settlement Agreement contained no causation
requirement beyond the revenue and related tests set forth in an exhibit
to that agreement. The district court also held that the absence of a
further causation requirement does not defeat class certification or
invalidate the settlement under the federal class certification rule or
Article III of the US Constitution. On 30 December 2013, BP filed a
motion with the Fifth Circuit requesting an injunction that would prevent
the claims administrator from making awards to claimants whose alleged
injuries are not fairly traceable to the spill. In a 2-1 decision 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 filed a petition on 17 March 2014 requesting that all active Fifth Circuit
judges review the business economic loss panel’s 3 March 2014
decision. On 19 May 2014, the Fifth Circuit declined (in a 5-8 decision) to
grant further review of the 3 March 2014 decision.

On 21 May 2014, BP asked the Fifth Circuit to stay the issuance of the
mandate transferring the case back to the district court until the US
Supreme Court could decide whether to review the Fifth Circuit’s
decision. The Fifth Circuit denied BP’s request for a stay on 27 May 2014,
and issued its mandate on 28 May 2014. On the same day, the district
court dissolved the injunction that had halted the processing and
payment of business economic loss claims and instructed the claims
administrator to resume the processing and payment of claims.

On 28 May, BP filed an application with the US Supreme Court seeking to
recall and stay the Fifth Circuit’s mandate in order to halt the processing
and payment of business economic loss claims pending further review. The
US Supreme Court denied BP’s application on 9 June 2014.

On 1 August 2014, BP filed a petition for certiorari with the US Supreme
Court for review of the Fifth Circuit’s decision upholding the district
court’s ruling that the Economic and Property Damages Settlement
Agreement contained no causation requirement beyond the revenue and
related tests set forth in an exhibit to that agreement, as well as a related
decision by a different panel of the Fifth Circuit similarly interpreting the
Economic and Property Damages Settlement Agreement to permit
payment to business economic loss claimants whose losses (if any) were
not caused by the spill. The US Supreme Court denied BP’s petition for
certiorari on 8 December 2014. Accordingly, the effective date of the
Economic and Property Damages Settlement Agreement is 8 December
2014, and the final deadline for filing all claims other than those that fall
into the Seafood Compensation Program is 8 June 2015.

On 2 September 2014, BP filed a motion seeking an order removing
Patrick Juneau from his roles as claims administrator and settlement
trustee for the Economic and Property Damages Settlement. On
10 November 2014, the district court denied BP’s motion. BP appealed
this decision to the Fifth Circuit on 18 November 2014.

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 in 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 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 was 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 Fund should be
returned as a result.

On 19 September 2014, the district court designated-neutrals appointed
to preside over the settlement of the seafood program (the Neutrals)
submitted to the district court their report on recommendations for the
Seafood Compensation Program supplement distribution
(Recommendations). The Neutrals observed that there remain some
claims against the Fund which have not been paid, and that BP has filed a
motion which seeks a return of part of the Fund, on the basis that it is
currently impossible to fully distribute the balance of the Fund. The
Neutrals recommended that the district court target a $500 million partial
distribution in the second round of payments using a proportionate
distribution method. The district court issued an order filing the
Recommendations into the court record and requiring that any objections
to or comments on the Recommendations to be filed by 20 October
2014. BP filed a response asserting that the district court should not yet
order second round distributions on the basis that, amongst other things,
the first round distributions are not complete. On 18 November 2014, the
district court approved the Neutrals’ Recommendations and
disbursement of funds commenced in early 2015.

Medical Benefits Class Action Settlement (Medical Settlement)
The district court approved the Medical Settlement Agreement (MSA) in
a final order and judgment on 11 January 2013. The effective date was
12 February 2014. As of 9 January 2015, the claims administrator under
the Medical Settlement (the Medical Claims Administrator) had received
12,418 claim forms, including 11,703 for certain Specified Physical
Conditions (SPCs), and has determined 774 claims to be eligible for
monetary compensation totalling approximately $1,542,500. For those
claimants seeking benefits under the Periodic Medical Consultation
Program, approximately 8,411 claims have been determined to be
eligible. The deadline for submitting claims for SPCs under the MSA was
12 February 2015. BP does not yet know the total number of claims
submitted, however a large volume of such claims is anticipated. The
Medical Claims Administrator issued a policy statement, with which BP
agrees, classifying physical conditions first diagnosed after 16 April 2012
as Later-Manifested Physical Conditions (LMPC), which requires a class
member seeking compensation to file a notice of intent to sue that
allows BP the option to mediate the claim in lieu of litigation. On 23 July
2014, the district court issued an order affirming the policy statement. On
26 November 2014, the district court directed the Medical Claims

Administrator to issue another policy statement regarding the impact of
the release provisions under the MSA on the filing of SPC claims and
LMPC claims, which was filed on 17 December. The district court’s
decision to either adopt, modify or reject the policy statement remains
pending.

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 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. The Fifth Circuit affirmed the district court’s ruling on
24 February 2014. Several of the parishes sought Supreme Court review,
which BP opposed. On 20 October 2014, the US Supreme Court declined
to hear the appeal.

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
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. 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 non-US 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

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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
actions against BP related to the Incident, which have been consolidated
with MDL 2179. On 19 April 2013, the State of Alabama filed an 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, other economic damages and natural resource 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, 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 February 2014, BP moved to strike the State of Alabama’s jury trial
demand as to its claim for compensatory damages under OPA 90. BP’s
motion remains pending.

On 5 March 2014, the State of Florida filed a lawsuit (which has since
been consolidated with MDL 2179) to declare various BP entities (and
other entities) liable for removal costs and natural resource damages.

OPA Test Case Proceedings
Seven OPA test cases will address certain OPA 90 liability questions
focusing on, among other issues, whether plaintiffs’ alleged losses tied
to the 2010 federal government moratoria on deepwater drilling and
federal permit delays are compensable. On 3 June 2014 the district court
entered an Agreed Upon Scheduling Order for these test cases. That
scheduling order has now been suspended indefinitely with no new
deadlines being established.

State of Alabama Damages Case Proceedings
On 16 July 2014 the district court issued a scheduling order for the State
of Alabama’s economic damages claims against BP and other parties and
a request by the district court for the parties to set aside the month of
November 2015 for a trial. That scheduling order has now been
suspended indefinitely with no new deadlines being established.

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
will come from the $20-billion Trust fund. BP and the trustees have
reached agreement 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 underway, and 44 projects that were filed with

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the court on 2 October 2014, following a regulatory review and public
comment process. As part of the project agreements, BP will receive
Natural Resource Damages (NRD) restoration credits that can be used to
offset related NRD restoration obligations, either in whole or in part.

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 has taken place, and the
parties filed cross-motions for summary judgment that were fully briefed
by 19 May 2014. The district court has not acted and the cross motions
remain to be decided.

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.

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.

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. 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.
Following briefing, oral argument was heard on the appeal on 27 October
2014 and the appeal is now under review.

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
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. On 13 February 2015 the Supreme Court of
Texas held that the insurance BP is entitled to receive as an additional
assured is limited to the liabilities that Transocean assumed in the drilling
contract which does not include liabilities for damages arising from sub-
surface pollution.

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 securities fraud claims. Many of these lawsuits
have been consolidated or co-ordinated in federal district court in
Houston (MDL 2185).

Securities class action
On 13 February 2012, the federal district court in Houston in MDL 2185
issued two decisions (the February 2012 ruling) 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 February 2012 ruling dismissed all the claims of the ordinary
shareholders, and 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. In addition, all of the claims of a smaller purported
subclass were dismissed 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 the February 2012
ruling; 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 the February 2012 ruling. 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 eight of the statements at issue
in the motion and also dismissing all claims against former BP employee
Andrew Inglis. On 20 May 2014, the judge denied plaintiffs’ motion to
certify a proposed class of ADS purchasers before the Deepwater
Horizon explosion (from 8 November 2007 to 20 April 2010) and granted
plaintiffs’ motions to certify a class of post-explosion ADS purchasers
from 26 April 2010 to 28 May 2010 and to amend their complaint to add
one additional alleged misstatement. Both parties sought permission to
appeal from the district court’s class certification decisions and on 3 July
2014, the Fifth Circuit granted both parties’ requests. Briefing on those
appeals is expected to conclude in March 2015.

The trial of the securities fraud claims of the class of post-explosion ADS
purchasers has been scheduled to commence on 11 January 2016.

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
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 April 2014, 27 additional cases were filed
in Texas state and federal courts (later consolidated into 24 actions) by
pension or investment funds or advisers against BP entities and current
and former officers and directors, asserting state, federal, and non-US
law claims and seeking damages for alleged losses that those funds
suffered because of their purchases of BP ordinary shares and/or ADSs.
Two cases were filed in New York federal court by funds that purchased
BP ordinary shares and ADSs, asserting state and federal law claims. All
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 29 cases
dismissing a subset of the claims. 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
(plaintiffs in one of the first three cases defendants moved to dismiss)
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 for a second time, and on 7 April 2014, the
judge dismissed the Ohio action with leave to replead English law claims
within 30 days. On 8 June 2014, the Ohio funds filed a second amended
complaint asserting only English law claims. On 30 September 2014, the
court granted in part and denied in part the defendants’ motion to dismiss
10 cases. The court dismissed the negligent misstatement claims in all
but one of the 10 cases and dismissed claims in these cases based on
certain public and private misstatements. The court also rejected BP’s
arguments that the ordinary share claims of the non-US plaintiffs should
be heard in England. On 29 October 2014, the case brought by the Ohio
funds was transferred to federal court in Houston for all purposes. On
30 December 2014, defendants answered the complaints in 11 cases.
Amended complaints in the remaining 15 cases are due by 1 April 2015.

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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 against BP. 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. On 14 August 2014, the Ontario Court of Appeal held
that the case should be stayed and that the claims made on behalf of
Canadian residents who purchased BP ordinary shares and ADSs on
exchanges outside of Canada should be litigated in those countries, and
granted leave for the plaintiff to amend the complaint to assert claims
only on behalf of Canadian residents who purchased ADSs on the
Toronto Stock Exchange. On 10 October 2014, the plaintiff filed an
application for leave to appeal to the Supreme Court of Canada. Briefing
on that application concluded on 25 November 2014.

Dividend-related proceedings
On 5 July 2012, the federal district court in Houston 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 an additional 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 action on 19 February 2014. On 18 June 2014, the
court dismissed the case on the ground that the courts of England are
the more appropriate forum for the litigation. On 18 July 2014, the
plaintiff appealed that decision to the Fifth Circuit. Briefing on that appeal
concluded on 24 December 2014.

ERISA
On 30 March 2012, the federal district court in Houston 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. On 15 July 2014, the Fifth Circuit remanded the case to the
district court in light of new pleading standards recently set forth by the
US Supreme Court. On 18 September 2014, the plaintiffs filed a motion
seeking leave to amend their complaint. Defendants opposed that
motion. On 15 January 2015, the district court granted in part and denied
in part the motion to amend, permitting plaintiffs to amend their
complaint to allege some of their proposed claims against certain
defendants. Plaintiffs filed an amended complaint on 12 February 2015.

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
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

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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 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 five years. In addition, $350 million
will be paid to the National Academy of Sciences (NAS) over five years.
BP made its required payments that were due in March and April 2013,
January 2014, and January 2015 totalling $1.521 billion. 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 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, its second payment of $175 million
on 1 August 2013, and the final instalment of $175 million, plus accrued
interest, on 1 August 2014.

BP’s November 2012 agreement with the US government does not
resolve the DoJ’s civil claims, such as those 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 were 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.

In addition, the charges to which BPXP pleaded guilty included one
misdemeanour count under the Clean Water Act that, by operation of
law, triggered 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.

On 13 March 2014, BP, BPXP, and all other temporarily suspended BP
entities entered into an administrative agreement with the EPA
resolving all issues related to suspension or debarment arising from the
Incident, allowing BP entities to enter into new contracts or leases with
the US government. Under the terms and conditions of the
administrative agreement, which will apply for five years, BP has agreed
to a set of safety and operations, ethics and compliance and corporate
governance requirements.

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
for a Coastal Use Permit to remove certain ’orphan’ anchors that had
been placed in coastal waters to secure the containment boom during oil
spill response operations in 2010. 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 including that the Order is pre-empted by federal law. On
7 August 2014, the court entered a final judgment providing that the
Order was pre-empted on the basis of impossibility and obstacle
pre-emption. The LDNR did not file a notice of appeal and the time period
to file such notice has expired.

Pending investigations and reports relating to the Deepwater
Horizon oil spill CSB investigation
The US Chemical Safety and Hazard Investigation Board (CSB) conducted
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 18 September 2014, in
response to Transocean’s challenge to the CSB’s jurisdiction to
investigate the Incident, the Fifth Circuit affirmed the district court’s order
enforcing CSB’s administrative subpoenas against Transocean. BP has
produced documents in compliance with the CSB’s document
subpoenas. Separately the CSB released the first two volumes of its
three-volume report on its investigation into the Incident at a public
hearing in Houston on 5 June 2014. The first two volumes provide an
introduction to the Incident as well as the CSB’s findings regarding the
operation of the blowout preventer and other technical issues. The CSB
has indicated that it plans to release Volume 3 (concerning the role of the
regulator in the oversight of the offshore industry and organizational and
cultural factors) in or around March 2015.

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.
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. On 15 May 2014,
FERC denied the motion to dismiss and the matter has been set for a
hearing before an Administrative Law Judge in March 2015.

Canadian Natural Resource
The US Commodity Futures Trading Commission (CFTC) is currently
investigating certain practices relating to crude oil pipeline nominations
procedures on Canadian pipelines. On 17 November 2014, the CFTC
Enforcement Staff notified BP that it intends to recommend an
enforcement action naming certain parties, including several BP entities,
alleging violations of the anti-fraud and false reporting provisions of the
Commodity Exchange Act in connection with these nomination
procedures and related trades. On 17 December 2014 BP submitted a
detailed defence responding to the allegations in the notice and
challenging the CFTC’s jurisdiction over the alleged conduct.

Investigations by the FERC and CFTC into BP’s trading activities continue
to be conducted from time to time.

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 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

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an Administrative Law Judge from the OSH Review Commission. The
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 and briefing was completed in the
first half of 2014. The Review Commission is not expected to issue its
decision until 2015 at the earliest.

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, based on alleged
misrepresentations concerning the integrity of the Prudhoe Bay pipeline
before its shutdown on 6 August 2006. The BP p.l.c. shareholder filed an
amended complaint, in response to which BP filed a 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

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subsea and other systems. BP is the operator and 56% interest owner of
the Atlantis unit which is in production in the Gulf of Mexico. On
21 August 2014, the court granted BP’s motions for summary judgment.
On 28 August 2014, the court entered final judgment in favour of BP. In
September 2014 the plaintiff filed a motion for reconsideration, which BP
opposed. The judge took this on advisement. A decision of the court is
awaited.

Bolivia
In respect of Pan American Energy’s arbitration case for compensation
for the expropriation of its shares in Empresa Petrolera Chaco S.A.
(Chaco) which commenced in March 2012 against the Republic of Bolivia,
on 18 December 2014, the Republic of Bolivia and Pan American Energy
signed a $357 million settlement agreement and agreed to terminate the
arbitration.

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. Related inquiries
and requests for information have also been received from US and other
regulators following the European Commission’s actions, including from
the Japanese Fair Trade Commission, the Korean Fair Trade Commission,
the Federal Trade Commission (FTC) and the CFTC. On 1 October 2014,
BP was informed by the FTC that it was closing its investigation. The
other investigations remain open and there is no deadline for the
completion of the inquiries.

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.

California False Claims Act matters
On 4 November 2014 the California Attorney General filed a notice in
California state court that it was intervening in a previously-sealed
California False Claims Act (CFCA) lawsuit filed by relator Christopher
Schroen against BP, BP Energy Company, BP Corporation North America
Inc., BP Products and BPAPC. On 7 January 2015, the California Attorney
General filed a complaint in intervention alleging that BP violated the
CFCA and the California Unfair Competition Law by falsely and
fraudulently overcharging California state entities for natural gas. The
relator’s complaint makes similar allegations, in addition to individual
claims. The complaints seek treble damages, punitive damages, penalties
and injunctive relief.

See Financial statements – Note 31 for additional information on the
group’s legal proceedings.

International trade sanctions
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 and EU sanctions
(Sanctioned Countries). Sanctions restrictions continue to be insignificant
to the group’s financial condition and results of operations. BP monitors
its activities with Sanctioned Countries, persons from Sanctioned
Countries and individuals and companies subject to US and EU sanctions
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.
Additionally, the Iran Threat Reduction and Syria Human Rights Act of
2012 (ITRA) added Section 13(r) to the Securities Exchange Act of 1934,
as amended (the Exchange Act), and requires that issuers 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 the North Sea Rhum field (Rhum) and
the Azerbaijan Shah Deniz field (Shah Deniz), in which Naftiran Intertrade
Co. Limited and NICO SPV Limited (collectively, NICO) or Iranian Oil
Company (U.K.) Limited (IOC UK) have interests. Additionally, BP has
interests in a gas marketing entity and a gas pipeline entity in which
NICO or IOC UK have interests, although both entities (and their related
assets) are located outside Iran. Production was suspended at Rhum (in
which IOC UK has a 50% interest) in November 2010. 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 assumed control of and now manages IOC UK’s interest
in the Rhum field, thereby permitting Rhum operations to recommence in
accordance with applicable EU regulations and in compliance with US
laws and regulations. Operations at the Rhum gas field recommenced in
mid-October 2014 in accordance with this Temporary Scheme.

Shah Deniz, 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 BP’s policy is that it shall not purchase
or ship crude oil or other products of Iranian origin. Participants in non-BP
controlled or operated joint arrangements* 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 it shall not sell crude oil or other
products into Iran. BP currently holds an interest in a non-BP operated
Indian joint venture* which sold crude oil to an Indian entity in which
NICO holds a minority, non-controlling stake. Those sales ceased in
January 2014.

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 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 or other partners may sell or
deliver fuel to airlines from Sanctioned Countries or flights to Sanctioned
Countries without BP’s prior knowledge or consent. BP has registered
and paid required fees for patents and trade marks in Sanctioned
Countries.

BP sells lubricants in Cuba through a 50:50 joint arrangement and trades
in small quantities of lubricants.

During 2014 the US and the EU have imposed sanctions on certain
Russian activities, individuals and entities, including Rosneft. Certain
sectoral sanctions also apply to entities owned 50% or more by entities
on the relevant sectoral sanctions list. Ruhr Oel GmbH (ROG) is a 50:50
joint operation with Rosneft, operated by BP, which holds interests in a
number of refineries in Germany. To date, these sanctions have had no
material adverse impact on BP or ROG.
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:

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 the field, 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. Operations at the Rhum gas field recommenced in mid-
October 2014 in accordance with the UK government’s Temporary
Scheme (see above). During the year ended 31 December 2014, BP
recorded gross revenues of $8.86 million related to its interests in Rhum.
BP had no net profits related to Rhum during the year ended
31 December 2014, recording an overall loss of $204.5 million (net)
following an impairment write-off of $198 million in the fourth quarter of
2014.

BP currently intends to continue to hold its ownership stake in the Rhum
joint arrangement.

Material contracts
On 13 March 2014, BP, BPXP, and other BP entities entered into an
administrative agreement with the US Environmental Protection Agency,
which resolved all issues related to the suspension or debarment of BP
entities arising from the 20 April 2010 explosions and fire on the semi-
submersible rig Deepwater Horizon and resulting oil spill. The
administrative agreement allows BP entities to enter into new contracts
or leases with the US government. Under the terms and conditions of
this agreement, which will apply for five years, BP has agreed to a set of
safety and operations, ethics and compliance and corporate governance
requirements. The agreement is governed by federal law.

Property, plant and equipment
BP has freehold and leasehold interests in real estate and other tangible
assets 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 2014 and the group percentage of ordinary share
capital see Financial statements – Note 35. For information on significant
joint ventures* and associates* of the group see Financial statements –
Notes 14 and 15.

Related-party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 14 and Note
15. 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 2014 to 17 February 2015.

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

* Defined on page 252.

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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 64). 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 64). Mr Nelson is the audit committee financial
expert as defined in Item 16A of Form 20-F.

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’.

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,
officers and members of the board. This was updated (and published) in
July 2014.

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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.

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.

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 2014 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 2014 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 2014 has been
audited by Ernst & Young, an independent registered public accounting
firm, as stated in their report appearing on page 95 of BP Annual Report
and Form 20-F 2014.

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.

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 34 and
Audit committee report on page 64 for details of fees for services
provided by auditors.)

Directors’ report information
This section of BP Annual Report and Form 20-F 2014 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, on appointment 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 2014. During the year, a review of the terms
and scope of the policy was undertaken. The 2013 policy was extended
into 2014 and subsequently renewed during 2014 into 2015. 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 46, Liquidity and capital resources on page
211 and Financial statements – Notes 27 and 28.

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 27.

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 44.

Employee share schemes
Certain shares held by the Employee Share Ownership Plan trusts
(ESOPs) carry voting rights. Voting rights in respect of such shares are
exercisable via a nominee.

Greenhouse gas emissions
The disclosures in relation to greenhouse gas emissions are included in
Corporate responsibility – Environment and society on page 42.

Disclosures required under Listing Rule 9.8.4R
The information required to be disclosed by Listing Rule 9.8.4R can be
located as set out below:

Information required
(1) Amount of interest capitalized
(2) – (14)

Page
123
Not applicable

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, (1) certain statements in the Chairman’s letter (pages
6-7), the Group chief executive’s letter (pages 8-9), the Strategic report

* Defined on page 252.

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(inside front cover and pages 1-50) and Additional disclosures (pages 207-
242), including but not limited to statements under the headings ‘Our
market outlook’, ‘Beyond 2035’, ‘Our business model’, ‘Our strategy’,
‘Outlook’ and ‘Outlook for 2015’, and including but not limited to
statements regarding plans and prospects relating to future value
creation, capital discipline and growth in sustainable free cash flow; plans
to develop resources, increase production, strengthen BP’s portfolio of
high-return and longer-life assets and unlock value from BP’s resource
base; plans relating to future workforce size, initiatives and composition,
including workforce diversity; expectations regarding the future level of
oil and gas prices and industry product supply, demand and pricing in the
near term and long term and BP’s outlook and projections of future
energy trends, including the role of oil, gas and renewables therein; plans
to form key partnerships and relationships with governments, customers,
partners, communities, suppliers and other institutions; expectations
regarding and timing of planned and future acquisitions and divestments,
including the completion of $10 billion of divestments in 2015;
expectations regarding the current and future prospects of BP’s
discoveries, resources, reserves and positions; expectations regarding
BP’s reported and underlying production in 2015; 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 of such projects;
expectations regarding Rosneft’s future share price and dividend growth
and BP’s plans to explore future opportunities with Rosneft; plans
regarding growing operating cash flow and returns in Downstream,
including by leveraging assets, portfolio management, customer
relationships, technology and trading activity; expectations regarding the
2015 environment for refining and petrochemicals margins; expectations
regarding 2015 refinery turnarounds and future refinery operations;
expectations regarding improvements in cash break-even performance,
earnings potential and future plant events in the petrochemicals
business; expectations regarding future safety performance and plans to
enhance safety, cybersecurity, compliance and risk management; Air
BP’s strategic aims; the future strategy for and planned investments in
alternative energies; the expected annual charges of Other business and
corporate for 2015; expectations regarding the actions of contractors and
partners and their terms of service; expectations regarding future
environmental regulations, their impact on BP’s business and plans to
reduce BP’s environmental impact; expectations regarding changes in
laws and regulations and their impact on BP’s business; plans to increase
efficiency, reliability and product quality, improve margins and create new
market opportunities; expectations regarding future Upstream
operations, including agreements or contracts with or relating to TEPCO,
BP’s CATS business, Tangguh and CNOOC, BP’s joint-ownership
interests in exploration blocks and plans to drill therein; plans to transfer
operatorship of certain fields, expectations of awards from award rounds;
plans related to the Alaska LNG project and the Canadian oil sands; plans
and expectations regarding the Point Thomson production facility, the
Angola LNG plant, the exploration and production-sharing agreement in
Libya, the North Damietta offshore concession, exploration in Morocco,
exploration in India, the Sanga-Sanga CBM PSA, the Southern Gas
Corridor, the Khazzan field, the Gorgon LNG plant and the Ceduna Sub
Basin; expected expirations of concessions, contracts and exploration
periods; projections regarding oil and gas reserves, including recovery
and turnover time thereof; plans regarding compliance with ITRA rules,
sanctions and reporting requirements, including in relation to BP’s stake
in the Rhum joint arrangement and future engagement in business with
Iran; plans to take action under and comply with the EPA Administrative
Agreement; plans with regard to the timing of and actions to be taken at
the AGM, including amendments to the proposal of amendments to the
Articles of Association; expectations regarding future restoration or other
actions to be taken as a result of the Deepwater Horizon incident and
related proceedings and their impact on BP’s business; 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; (2) certain statements in
Corporate governance (pages 51-71) and the Directors’ remuneration
report (pages 72-88) with regard to the anticipated future composition of
the board of directors; the board’s goals and areas of focus stemming
from the board’s annual evaluation; plans regarding and the timing of

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future audit contract tendering and areas of focus for the audit
committee; the expected percentage of performance shares that will
vest based on performance outcomes; and plans and expectations with
regard to the remuneration, pensions and other benefits of executive
directors, including disclosure of targets, future review schedules,
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 (3) certain statements in the Strategic report (inside
front cover and pages 1-50) and Additional disclosures (pages 211-212),
with regard to future dividend and optional scrip dividend payments;
future capital expenditures and capital investment, including estimated
2015 levels thereof, 2015 taxation, future working capital and cash
management, gearing and the net debt ratio; BP’s intention to maintain a
strong cash position; 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 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; production-sharing
agreements effects; operational and safety problems; potential lapses in
product quality; 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; the timing and
amount of future payments relating to the Gulf of Mexico oil spill;
exchange rate fluctuations; development and use of new technology;
recruitment and retention of a skilled workforce; the success or
otherwise of partnering; the actions of competitors, trading partners,
contractors, subcontractors, creditors, rating agencies and others; our
access to future credit resources; business disruption and crisis
management; the impact on our reputation of ethical misconduct and
non-compliance with regulatory obligations; trading losses; major
uninsured losses; 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 48-50). 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.

Shareholder
information

244 Share prices and listings

244 Dividends

245 UK foreign exchange controls on dividends

245 Shareholder taxation information

247 Major shareholders

247 Annual general meeting

247 Memorandum and Articles of Association

250 Purchases of equity securities by the issuer and

affiliated purchasers

251 Fees and charges payable by ADSs holders

251 Fees and payments made by the Depositary to the

issuer

251 Documents on display

252 Shareholding administration

252 Exhibits

252 Abbreviations, glossary and trade marks

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243

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 8.00am to 4.30pm 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 4 New York Plaza, Floor 12, New York, NY, 10004, 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
2010
2011
2012
2013
2014
Year ended 31 December
2013: First quarter

Second quarter
Third quarter
Fourth quarter

2014: First quarter

Second quarter
Third quarter
Fourth quarter

2015: First quarter (to 17 February)

Month of
September 2014
October 2014
November 2014
December 2014
January 2015
February 2015 (to 17 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

658.20
514.90
512.00
494.20
526.80

482.33
485.43
477.53
494.20
510.00
526.80
525.80
455.45
463.10

494.90
455.45
452.45
439.80
445.68
463.10

296.00
361.25
388.56
426.50
364.40

426.50
437.25
430.30
426.55
462.64
467.10
440.72
364.40
376.70

440.72
405.35
408.80
364.40
376.70
426.35

62.38
49.50
48.34
48.65
53.48

45.45
44.27
43.75
48.65
51.02
53.48
53.48
44.14
42.10

48.11
44.14
43.08
41.59
40.44
42.10

26.75
33.62
36.25
39.99
34.88

39.99
40.12
40.51
41.30
45.83
47.14
43.80
34.88
34.93

43.80
39.45
39.19
34.88
34.93
39.19

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.

On 17 February 2015, 883,647,170.5 ADSs (equivalent to approximately
5,301,883,023 ordinary shares or some 29.07% of the total issued
share capital, excluding shares held in treasury) were outstanding and
were held by approximately 95,858 ADS holders. Of these, about
94,687 had registered addresses in the US at that date. One of the
registered holders of ADSs represents some 979,038 underlying
holders.

On 17 February 2015, there were approximately 270,163 ordinary
shareholders. Of these shareholders, around 1,570 had registered
addresses in the US and held a total of some 4,005,034 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.

Dividends
BP’s current policy is to pay interim dividends on a quarterly basis on its
ordinary shares.

Its 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. 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 8.

A Scrip Dividend Programme (Scrip Programme) was approved by
shareholders in 2010. It 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 company intends to propose a resolution to the shareholders at the

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BP Annual Report and Form 20-F 2014

next AGM that the Scrip Programme be renewed for a further three
years. The operation of the Scrip Programme is always subject to the
directors’ decision to make the Scrip Programme offer available in
respect of any particular dividend. Should the directors decide not to offer
the Scrip Programme in respect of any particular dividend, cash will be
paid automatically instead.

Future dividends will be dependent on future earnings, the financial
condition of the group, the Risk factors set out on page 48 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 211.

The following table shows dividends announced and paid by the
company per ADS for the past five years.

Dividends per ADSa
2010

2011

2012

2013

2014

UK pence
US cents

UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents

March
52.07
84

June September December
–
–

–
–

Total
52.07
84

26.02 25.68
42
30.57 30.90
48
36.01 35.01
54
34.24 34.84
58.5

25.90
42
30.10
48
34.58
54
35.76
58.5

26.82 104.42
168
33.53 125.10
198
34.80 140.40
219
38.26 143.10
234

a Dividends announced and paid by the company on ordinary and preference shares are provided

in Financial statements – Note 8.

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 or those
sanctions adopted by the UK government which implement resolutions
of the Security Council of the United Nations.

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 or those sanctions adopted by the UK
government which implement resolutions of the Security Council of the
United Nations.

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,
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
further assumes that each obligation in the Deposit Agreement and any
related agreement will be performed in accordance with its terms.

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 that
constitute ‘qualified dividend income’ will be taxable to the holder at a
preferential rate, 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

BP Annual Report and Form 20-F 2014

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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.

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 that carries on a trade or
profession or vocation in the UK through a branch or agency or a
corporation that carries on a trade, profession or vocation in the UK,
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.

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Additional tax considerations
Scrip Dividend Programme
The company has an optional Scrip 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
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, is subject to a
3.8% tax on the lesser of (1) the US holder’s ‘net investment income’
(or ‘undistributed net investment income’ in the case of an estate or
trust) 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 is between $125,000 and
$250,000, depending on the individual’s circumstances). A holder’s net
investment income generally includes its dividend income and its net
gains from the disposition of shares or ADSs, unless such dividend
income or net gains are derived in the ordinary course of the conduct of a
trade or business (other than a trade or business that consists of certain
passive or trading activities). If you are a US holder that is an individual,
estate or trust, you are urged to consult your tax advisors regarding the
applicability of the Medicare tax to your income and gains in respect of
your investment in the shares or ADSs.

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.

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
56,090
95,613
107,541
10,659
773
659

Percentage of total
ordinary shareholders
20.67
35.24
39.63
3.93
0.29
0.24

Percentage of total
ordinary share capital
excluding shares
held in treasury
0.02
0.28
1.79
1.18
1.59
95.14

271,335

100.00

a Includes JPMorgan Chase Bank, N.A. holding 28.79% 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.

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
55,981
25,960
13,816
740
8
1

96,506

Percentage of total
ADS holders
58.01
26.90
14.32
0.77
0.00
0.00

Percentage of total
ADSs
0.35
1.42
4.14
1.42
0.13
92.54

100.00

a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 979,038 underlying shareholders.

As at 31 December 2014, there were also 1,483 preference
shareholders. Preference shareholders represented 0.46% and ordinary
shareholders represented 99.54% 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 2014 BlackRock, Inc held 5.91%, The Capital Group
Companies, Inc held 3.31% and Legal & General Group plc held 3.21% of
the voting rights of the issued share capital of the company. As at
17 February 2015 BlackRock, Inc held 6.25%, The Capital Group
Companies, Inc held 3.51% and Legal & General Group plc held 3.27% 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 17 February 2015:

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

5,301,883,023

1,139,520,000

29.07

6.25

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 17 February 2015:

Holder

The National Farmers Union Mutual

Insurance Society

M & G Investment Management Ltd.

Duncan Lawrie Ltd.

Holder

The National Farmers Union Mutual

Insurance Society

M & G Investment Management Ltd.

Smith & Williamson Investment

Management Ltd.

Bank Julius Baer

Barclays Bank PLC.

Holding of 8%
cumulative first
preference shares

Percentage
of class

945,000

528,150

364,876

13.07

7.30

5.04

Holding of 9%
cumulative second
preference shares

Percentage
of class

987,000

644,450

333,200

294,000

279,172

18.03

11.77

6.09

5.37

5.10

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
combined holdings, thereby taking their interest in shares above the 3%
threshold as of 1 September 2012.

Smith and Williamson Holdings Limited disposed of its interest in 32,500
8% cumulative first preference shares during 2014.

In accordance with DTR 5.6, BlackRock, Inc. notified the company that its
indirect interest in ordinary shares decreased below 5% during 2014.

UBS Investment Bank notified the company that its indirect interest in
ordinary shares increased above 3% on 9 February 2015 and that it
decreased below the notifiable threshold on 16 February 2015.

As at 17 February 2015, the total preference shares in issue comprised
only 0.46% of the company’s total issued nominal share capital
(excluding shares held in treasury), the rest being ordinary shares.

Annual general meeting
The 2015 AGM will be held on Thursday 16 April 2015 at 11.30am 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 2015.

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 (the 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 251.

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. New Articles of Association are being proposed at our AGM in
2015.

BP Annual Report and Form 20-F 2014

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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.

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

248

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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 (Scrip
Programme) and to include provisions in the Articles of Association to
enable the company to operate the Scrip Programme. The Scrip
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 Scrip 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 on 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
quarters 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 (1) the capital paid up on such shares plus,
(2) accrued and unpaid dividends and (3) 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.

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 248 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 in 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, 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 or those sanctions adopted
by the UK government which implement resolutions of the Security
Council of the United Nations.

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.

Called-up share capital
Details of the allotted, called-up and fully-paid share capital at
31 December 2014 are set out in Financial statements – Note 29.

At the AGM on 10 April 2014, authorization was given to the directors
to allot shares up to an aggregate nominal amount equal to $3,076
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 $231 million, without having to offer such shares to
existing shareholders. These authorities were given for the period until
the next AGM in 2015 or 10 July 2015, whichever is the earlier. These
authorities are renewed annually at the AGM.

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Purchases of equity securities by the issuer and affiliated purchasers
In March 2013 BP began a share repurchase, or buyback, programme (the buyback programme) with an expected total value of up to $8 billion. The
decision to buy back shares followed the completion of the sale of BP’s 50% interest in TNK-BP to Rosneft. The programme expected to return to BP
shareholders an amount equivalent to the value of BP’s original investment in TNK-BP and to exceed that required to offset the earnings per share
dilution expected as a result of the sale of TNK-BP. It also reflected the reduction in BP’s asset base following its $38-billion divestment programme.
The buyback programme was completed in July 2014.

A further $2.3 billion of share repurchases were carried out in 2014 after the completion of the previously announced programme, funded by BP’s
continuing divestment of assets as announced in October 2013, and under the authority granted by shareholders at the 2014 AGM for BP to
repurchase up to 1.8 billion ordinary shares.

The following table provides details of share repurchase, or buyback, activity 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.

2014
January 2 – January 31
February 3 – February 28
March 3 – March 31
April 1 – April 30
May 1 – May 30
June 2 – June 30
July 1 – July 31
August 1 – August 29
September 1 – September 30
October 1 – October 31
November 3 – November 7
December 2 – December 22

2015
January 9 – January 30
February 2 to February 5

Number of
shares
purchased
by ESOPs or for
certain employee
share-based
payment plansb

Number
of shares
purchased as
part of the
programmec

Maximum
approximate
dollar value
of shares
yet to be
purchased
under the
programme
$ million

Total number
of shares
purchaseda

Average price
paid per share
$

162,240,000
48,436,545
36,410,000
17,980,000
17,386,000
18,082,500
23,927,485
70,519,200
123,054,453
75,398,500
8,029,320
51,149,002

8.09
8.06
8.03
8.16
8.54
8.68
8.57
8.05
7.66
7.02
7.02
6.28

2,000,000
–
–
–
–
–
8,300,000

– 162,240,000
46,436,545
36,410,000
17,980,000
17,386,000
18,082,500
23,927,485
62,219,200
– 123,054,453
75,398,500
–
8,029,320
–
20,749,002
30,400,000

31,600,000
6,960,000

6.27
6.50

31,600,000
6,960,000

–
–

1,194
819
527
380
232
75
–
–
–
–
–
–

–
–

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 11 April 2013 and 10 April 2014, authorization was given to the company to repurchase up to 1.9 billion and 1.8 billion ordinary shares, respectively, for the periods until the next AGM
in 2014 and 2015 or 11 July 2014 and 10 July 2015 respectively, being the latest dates by which an AGM must be held for the relevant year. This authorization is renewed annually at the AGM. The
total number of ordinary shares repurchased during 2014 was 611,913,005 at a cost of $4,796 million (including transaction costs) representing 3.36% of BP’s issued share capital excluding shares held
in treasury on 31 December 2014. All ordinary shares repurchased in 2013 and 2014 were cancelled in order to reduce BP’s issued share capital.

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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 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.
• Delivery by cable, telex, electronic and facsimile

transmission.

• 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 are subject to
agreement between the company
and the Depositary by billing holders
or by deducting charges from one or
more cash dividends or other cash
distributions.

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 2014. The Depositary reimbursed to the company, or paid
amounts on the company’s behalf to third parties, or waived its fees
and expenses, of $3,612,749.32 for the year ended 31 December 2014.

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 2014. 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 2014
$

400,000.00

2,223,141.13

901,224.03

88,384.16
3,612,749.32

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 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 2014 and BP Strategic Report 2014
are available online at bp.com/annualreport. To obtain a hard copy of
BP’s complete audited financial statements, free of charge, UK based
shareholders should contact BP Distribution Services by calling
+44 (0)870 241 3269 or by emailing bpdistributionservices@bp.com. If
based in the US or Canada shareholders should contact Issuer Direct by
calling +1 888 301 2505 or by emailing bpreports@precisionir.com.

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 and 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 its headquarters 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 239) 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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251

Shareholding administration
If you have any queries about the administration of shareholdings, such
as change of address, change of ownership, dividend payments, the
Scrip 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

Fax +44 (0)1484 601512

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

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 35 to the Financial
Statements)
Administrative Agreement dated as of 13 March 2014
among the US Environmental Protection Agency,
BP p.l.c., and other BP subsidiaries†
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.

****** Incorporated by reference to the company’s Annual Report on Form 20-F for the year

ended 31 December 2013.

# 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.

252

BP Annual Report and Form 20-F 2014

Abbreviations, glossary and trade marks
ADR
American depositary receipt.

ADS
American depositary share. 1 ADS = 6 ordinary shares.

Barrel (bbl)
159 litres, 42 US gallons.

bcf/d
Billion cubic feet per day.

bcfe
Billion cubic feet equivalent.

bcma
Billion cubic metres per annum.

b/d
Barrels per day.

boe/d
Barrels of oil equivalent per day.

DoJ
US Department of Justice.

GAAP
Generally accepted accounting practice.

Gas
Natural gas.

GWh
Gigawatts per hour.

IFRS
International Financial Reporting Standards.

KPIs
Key performance indicators.

LNG
Liquefied natural gas.

LPG
Liquefied petroleum gas.

mb/d
Thousand barrels per day.

mboe/d
Thousand barrels of oil equivalent per day.

mmb/d
Million barrels per day.

mmboe/d
Million barrels of oil equivalent per day.

mmBtu
Million British thermal units.

mmcf/d
Million cubic feet per day.

mmte
Million tonnes.

MWh
Megawatt per hour.

NGLs
Natural gas liquids.

PSA
Production-sharing agreement.

PTA
Purified terephthalic acid.

RC
Replacement cost.

SEC
The United States Securities and Exchange Commission.

Glossary
Unless the context indicates otherwise, the definitions for the following
glossary terms are given below.

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.

Consolidation adjustment – UPII
Unrealized profit in inventory arising on inter-segment transactions.

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 in Upstream on page 28 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
Contracts that 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, and 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
Contracts that 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, Oseberg and Ekofisk (BFOE). Forward
contracts are used in connection with the purchase of crude oil supplies
for refineries, products for marketing and sales of the group’s oil
production and refined products. 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 used from time to time, to settle obligations
under the contracts in cash rather than through physical delivery.
Because the physically settled transactions are delivered by cargo, the
BFOE contract additionally specifies a standard volume and tolerance.

Gas and power OTC markets are highly developed in North America and
the UK, where 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, the contracts specify delivery terms for the
underlying commodity. Some of these transactions are not settled
physically as they 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, products for marketing, or third-party
natural gas, or sales of the group’s oil production, oil products or 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.

Dividend yield
Sum of the four quarterly dividends declared in the year as a percentage
of the year-end share price on the respective exchange.

Fair value accounting effects
We use 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 historical cost. The related derivative instruments, however,
are required to be recorded at fair value with gains and losses recognized
in the income statement. This is 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
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.

IFRS require that inventory held for trading is 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 that are fair valued under IFRS. This results in measurement
differences in relation to recognition of gains and losses.

The way 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

BP Annual Report and Form 20-F 2014

253

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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.

total of finance debt plus shareholders’ interest. See Financial
statements – Note 25 for information on gross debt, which is the nearest
equivalent measure to net debt on an IFRS basis.

Free cash flow
Operating cash flow less net cash used in investing activities, as
presented in the condensed group cash flow statement.

Gearing
See Net debt and net debt ratio definition.

Hydrocarbons
Liquids and natural gas. Natural gas is converted to oil equivalent at 5.8
billion cubic feet = 1 million barrels.

Inventory holding gains and losses
The difference between the cost of sales calculated using the
replacement cost of inventory 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 historical
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 based on the
replacement cost of inventory. For this purpose, the replacement cost of
inventory is calculated using data from each operation’s production and
manufacturing system, either on a monthly basis, or separately for each
transaction where the system allows this approach. 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. See Replacement cost (RC) profit or loss definition below.

Joint arrangement
An arrangement in which two or more parties have joint control.

Joint control
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 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.

Liquids
Comprises crude oil, condensate and natural gas liquids. For reserves, it
also includes bitumen.

Major projects
Have a BP net investment of at least $250 million, or are considered to
be of strategic importance to BP or of a high degree of complexity.

Net debt and net debt ratio (gearing)
Non-GAAP measures. Net debt includes 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 claimed. The derivatives are reported on the balance sheet
within the headings ‘Derivative financial instruments’. We believe that
net debt and net debt ratio 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 net debt ratio is defined as the ratio of finance debt
(borrowings, including the fair value of associated derivative financial
instruments that are used to hedge foreign exchange and interest rate
risks relating to finance debt, plus obligations under finance leases) to the

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Net wind generation capacity
The sum of the rated capacities of the assets/turbines that have entered
into commercial operation, including BP’s share of equity-accounted
entities. The gross data is the equivalent capacity on a gross-JV basis,
which includes 100% of the capacity of equity-accounted entities where
BP has partial ownership.

Non-operating items
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 better to understand and evaluate
the group’s reported financial performance.

Operating capital employed
Non-GAAP measure. Total assets (excluding goodwill) less total liabilities,
excluding finance debt and current and deferred taxation.

Operating cash flow and operating cash
Net cash provided by (used in) operating activities as stated in the
condensed group cash flow statement. When used in the context of a
segment rather than the group, the terms refer to the segment’s share
thereof.

Operating management system (OMS)
BP’s OMS helps us manage risks in our operating activities by setting out
BP’s principles for good operating practice. It brings together BP
requirements on health, safety, security, the environment, social
responsibility and operational reliability, as well as related issues, such as
maintenance, contractor relations and organizational learning, into a
common management system.

Organic capital expenditure
Excludes acquisitions, asset exchanges, and other inorganic capital
expenditure. An analysis of capital expenditure by segment and region is
shown in Financial statements – Note 4.

Plant efficiency
Plant efficiency is calculated taking 100% less the ratio of total plant
deferrals divided by installed production capacity. Plant deferrals include
planned and unplanned deferrals associated with the topside plant and
where applicable the subsea equipment (excluding wells and reservoir).
Plant deferrals include breakdowns, planned events, turnarounds, and
weather.

Production-sharing agreement (PSA)
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.

Proved reserves replacement ratio
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.

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 downtime.

Refining marker margin (RMM)
The average of regional indicator margins weighted for BP’s crude
refining capacity in each region. Each regional marker margin is based on
product yields and a marker crude oil deemed appropriate for the region.
The regional indicator margins may not be representative of the margins
achieved by BP in any period because of BP’s particular refinery
configurations and crude and product slate.

Unit cash margin
Net cash provided by operating activities for relevant projects in the
Upstream segment, divided by the total number of barrels of oil and gas
equivalent produced for the relevant projects. It excludes dividends and
production for TNK-BP and Rosneft.
Trade marks

Trade marks of the BP group appear throughout this Annual Report
and Form 20-F in italics.
They include:
Aral
ARCO
BP
Castrol
EDGE
Field of the Future
Fluid Strength Technology

Titanium Fluid Strength Technology
SaaBre
Wild Bean Cafe
Permasense is a trade mark of Permasense
Limited.
M&S Simply Food is a registered trade
mark of Marks & Spencer plc.

Replacement cost (RC) profit or loss
Reflects the replacement cost of inventories sold in the period 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 that is required to
be disclosed for each operating segment under International Financial
Reporting Standards (IFRS). RC profit or loss for the group is not a
recognized GAAP measure. Management believes this measure 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 to changes in prices as well
as changes in underlying inventory levels. In order for investors to
understand the operating performance of the group excluding the
impact of 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 measure. See
Financial statements – Note 4.

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.

Tier 1 process safety events
Losses 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.

Tight gas
Natural gas reservoirs locked in hard sandstone rocks with low
permeability, making the underground formation extremely tight.

Underlying production
2014 underlying production, when compared with 2013, is after
adjusting for the effects of the Abu Dhabi onshore concession expiry in
January 2014, divestments and entitlement impacts in our production-
sharing agreements.

2015 underlying production, when comparing with 2014, is after
adjusting for divestments and entitlement impacts in our production-
sharing agreements.

Underlying RC profit or loss
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. See pages 209
and 210 for 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 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.

The Directors’ report on pages 51-71, 90, 167-196 and 207-255 was approved by the board and signed on its behalf by David J Jackson, company
secretary on 3 March 2015.

BP p.l.c.
Registered in England and Wales No. 102498

BP Annual Report and Form 20-F 2014

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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
3 March 2015

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Cross reference to Form 20-F

A.
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F.

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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.

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
History and development of the company
Business overview
Organizational structure
Property, plants and equipment
Unresolved Staff Comments
Operating and Financial Review and Prospects
Operating results
Liquidity and capital resources
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
Major shareholders
Related party transactions
Interests of experts and counsel
Financial Information
Consolidated statements and other financial information
Significant changes
The Offer and Listing
Offer and listing details
Plan of distribution
Markets
Selling shareholders
Dilution
Expenses of the issue
Additional Information
Share capital
Memorandum and articles of association
Material contracts
Exchange controls
Taxation
Dividends and paying agents
Statements by experts
Documents on display
Subsidiary information
Quantitative and Qualitative Disclosures about Market Risk
Description of securities other than equity securities
Debt Securities
Warrants and Rights
Other Securities
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

Page
n/a
n/a

208
n/a
n/a
48-50

ii, 2-5, 12-17, 21-38, 111-123, 129, 208, 211-216, 228-239
2-5, 10-17, 20-50, 119-123, 211-228, 252-255
ii, 160
26-28, 30-32, 128, 143,195-196, 213-224, 239
None

21-35, 38, 48-50, 100-110, 119-123, 144-147, 211-212
21-23, 105-106, 128, 142, 144-147, 211-212
16-17, 32, 123
10-11, 22-24, 29, 35
143, 211-212
212
n/a

52-57
72-88, 127, 135-141, 158
52-55, 59-60, 64-71, 74, 87
44-45, 159
45, 72-88, 158-159

247
131-133, 239
n/a

6, 94-166, 211, 228-239, 244-245
None

244
n/a
244
n/a
n/a
n/a

n/a
247-249
239
245
245-246
n/a
n/a
251
160
144-151

n/a
n/a
n/a
248-249, 251
None
None
95, 240-241
64, 240
240
159, 241
n/a
250
None
239-240
n/a
94-166
252

BP Annual Report and Form 20-F 2014

257

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Acknowledgements
Design
Typesetting RR Donnelley
Printing

SALTERBAXTER MSLGROUP

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Photography Ekaterina Anokhina, Ian Billingshurst,

Mehmet Binay, Jon Challicom,
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