BP Annual Report 2016 | Quarterlytics

FY2016 Annual Report · BP

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Annual
Report

and Form 20-F
2016

The energy we produce serves to
power economic growth and lift
people out of poverty. In the future,
the way heat, light and mobility are
delivered will change. We aim to
anchor our business in these changing
patterns of demand, rather than in the
quest for supply. We have a real
contribution to make to the world’s
ambition of a low carbon future.

Contents

Strategic report

Overview

BP at a glance
Chairman’s letter
Group chief executive’s letter
The changing world of energy

2
4
6
8
10 How we run our business

Strategy

14 Our strategy
18 Measuring our 2016 progress

Performance

20 Challenging global energy markets
21 Group performance
24 Upstream
30 Downstream
35 Rosneft
37 Other businesses and corporate
37 Gulf of Mexico oil spill
38 Alternative energy

40 Sustainability

40 Safety
43 Climate change
44 Value to society
44 Human rights
44 Local environmental impacts
45 Ethical conduct
46 Our people
47 How we manage risk
49 Risk factors

Corporate governance

Additional disclosures

Introduction from the chairman

51 Contents
52 Board of directors
58 Executive team
62
64 Board activity in 2016
68 Shareholder engagement
68
69 Audit committee
74

International advisory board

Safety, ethics and environment
assurance committee
Remuneration committee
76
78
Geopolitical committee
79 Chairman’s committee
79 Nomination committee
80

Directors’ remuneration report and
2017 policy

111 Directors’ statements

Financial statements

113 Contents

114 Consolidated financial statements

of the BP group

126 Notes on financial statements

187 Supplementary information on oil
and natural gas (unaudited)

215 Parent company financial statements

of BP p.l.c.

239 Contents

Including information on liquidity
and capital resources, oil and gas
disclosures, upstream regional
analysis and legal proceedings.

Shareholder information

271 Contents

Including information on dividends, our
annual general meeting and share prices.

280 Glossary
285 Non-GAAP measures reconciliations
288 Signatures
289 Cross-reference to Form 20-F
290 Information about this report

Glossary
Words with this symbol
in the glossary on page 280.

are defined

Cautionary statement

This document should be read in
conjunction with the cautionary
statement on page 269.

For a secure,
affordable
and sustainable
energy future.

BP Annual Report and Form 20-F 2016

BP at a glance

We are a global energy company
with wide reach across the
world’s energy system. We have
operations in Europe, North and
South America, Australasia, Asia
and Africa.

Scale

74,500

employees

18,000

retail sites

17,810

million barrels of oil equivalent –
proved hydrocarbon reservesa

countries

6,000+

marine voyages completed
by BP-operated and
chartered vessels

BP in action

Some highlights of our activities
around the world in 2016.

Started up the Point
Thomson major project .

Increased the number of M&S
Simply Food® and REWE®
convenience stores in Europe
and launched BP fuels with
ACTIVE technology.

Formed Aker BP, Norway’s
largest independent oil and gas
producer with Det norske.

Signed principles of
agreement on future
development of the ACG oil
field to 2050 in Azerbaijan.

Started up two major
projects in Algeria.

Completed Whiting
refinery’s largest turnaround.

Entered into a strategic
partnership with Fulcrum
BioEnergy® – a company that
produces sustainable jet fuel
from household waste.

Started up two major
projects and sanctioned
Mad Dog phase 2 in
the Gulf of Mexico.

Sanctioned our onshore
compression project
in Trinidad.

More than doubled our
production of ethanol
equivalent since 2011
in renewables.

Restarted Angola
LNG plant.

Acquired interests in gas
exploration blocks in offshore
Mauritania and Senegal with
Kosmos Energy.

BP and Rosneft separately
agreed to buy interests in
the Zohr gas field in Egypt
from Eni.

BP Annual Report and Form 20-F 2016

Performance

$115m

Data as at or for the year ended
31 December 2016 unless otherwise stated.

3.3

profit attributable to BP shareholders
(2015 $6.5bn loss)

million barrels of oil equivalent per day
– hydrocarbon productiona
(2015 3.2mmboe/d)

tier 1 process safety events
(2015 20)

$2.6bn

underlying replacement
cost profit
(2015 $5.9bn)

109%

group proved reserves
replacement ratio a b
(2015 61%)

a On a combined basis of subsidiaries

and equity-accounted entities.

b Including the impact of the Abu Dhabi onshore oil

concession renewal.

S
t
r
a
t
e
g
c
r
e
p
o
r
t
–
o
v
e
r
v
i
e
w

Agreed to extend the licence
area of the Khazzan gas field
in Oman and renewed our
interest in Abu Dhabi ADCO
onshore oil concession.

Completed a deal to conduct
exploration in East and West
Siberia with Rosneft.

Announced two agreements
with China National Petroleum
Company for shale gas
exploration in the Sichuan
Basin, and launched Castrol
MAGNATEC engine oil with
DUALOCK technology in
Downstream.

Gained approval to
develop the Tangguh
expansion project,
adding a third
LNG train .

Announced plans for a strategic
partnership with Woolworths®
to deliver fuel and convenience
offers in Australia.

More information

Group performance
Page 21

Upstream
Page 24

Downstream
Page 30

Rosneft
Page 35

Alternative energy
Page 38

See Glossary.

BP Annual Report and Form 20-F 2016

Chairman’s letter

We have shown great resilience and character: we
returned to profit and maintained our dividend. We had a
good year in a tough environment. We have set a new
strategic direction for BP – and we have a great team
carrying it out.

Caption: Members of the board
examine BP operations at Baku
in Azerbaijan.

Dear fellow shareholder,
2016 was a year of change on many fronts. The global
community witnessed further challenges raised by
economic, political and social forces, and many nations
experienced internal stresses and tensions, which
remain present. In the energy world, our world, it has
been a period of transition. From a 12-year low in oil
prices, to digital technologies that are transforming how
we work, and the drive to a lower carbon economy, our
team has had to manage through a period of uncertainty,
complexity and volatility.

Against this backdrop, we have shown great resilience
and character: we returned to profit and maintained our
dividend. We had a good year in a tough environment.
We have set a new strategic direction for BP – and we
have a great team carrying it out.

The record since 2010
BP’s performance in 2016 was based on the foundations
rebuilt following the 2010 Deepwater Horizon accident
– an event that could have put the very existence of our
company at risk.

Over the past six years, Bob Dudley and his team have
steered the business through the recovery from the crisis
of 2010 and then through the response to lower oil and
gas prices.

During that period, safety has improved significantly. The
portfolio has been strengthened. Operating cash flow
has remained strong. The dividend has been restored
and increased. Investment for growth has continued,
while capital and costs have been controlled. The
relationships on which we depend have been deepened.
And all of this has been done while managing a charge
of $63 billion for the 2010 accident, for which the major
liabilities have now been clarified and for which we have
a plan to manage the remaining payments and residual
litigation. All of this sets a firm base for the future, which
is bound to have its own challenges.

2016 performance and shareholder
distributions
In 2016 the team has again focused on the careful
stewardship of shareholders’ investments.

We continued making progress in safety performance,
with serious incidents and injury rates falling. We
delivered strong cash flow, disciplined capital spending
and lower costs. We met our cost reduction target a
year early. New major projects took shape. And we have
continued to invest in opportunities for future growth,
securing a set of innovative portfolio additions as well as
divesting non-strategic assets.

This performance enabled us to maintain the dividend at
10 cents per ordinary share through 2016 and the board’s
policy remains to grow sustainable free cash flow and
distributions to shareholders.

Looking ahead
We can now look forward and outward, and the board
and executive team have set out BP’s strategic priorities
for the future.

BP Annual Report and Form 20-F 2016Our refreshed strategy is designed to ensure BP is ‘good
for all seasons’ in an uncertain environment. It enables
us to compete in a world of volatile oil and gas prices,
changing customer preferences and of course, the
transition to a lower carbon future.

As our BP Energy Outlook 2035 predicts, the growth in
consumption of oil will gradually slow and likely peak.
This is a result of slowing demand growth, not limited
supply, as was once thought. In a world of longer-term
abundance, oil prices are likely to remain under pressure.
Focus will shift to greater efficiency and low-cost
production. Gas will grow as a cleaner alternative to
coal. Advanced fuels and lubricants will help motorists
reduce emissions. Renewable energy will grow rapidly to
become commercial at scale.

As a global business, we plan to play our part in this
energy transition. Our strategy provides BP with greater
agility – combining lower cost oil production, increasing
gas supply, greater market-led downstream activities,
and growing renewables and venturing businesses.

We are also proud to be playing a leading role among
our peers through the Oil and Gas Climate Initiative,
where Bob’s chairmanship has seen an unprecedented
convergence of national and international energy
companies to act on this issue.

Remuneration
At the 2016 AGM, we heard a clear message from
shareholders on executive pay. During the past year we
have sought to address these concerns, recognizing they
reflect the concerns of society more broadly.

The decisions we have taken, and for which we seek
shareholder approval, mark a significant break from past
policy. The total pay for executive directors in 2016 is
much reduced compared to 2015.

The policy we propose for 2017 and beyond is a simpler
approach to executive remuneration and reduces the
total amount executive directors can earn compared with
the previous policy. Executive reward will be driven even
more closely than before by the company’s performance
and shareholder returns. I particularly want to emphasize
that the future remuneration of senior management will
be directly linked to the delivery of our new strategic
priorities, including BP’s contribution to the longer-term
transition in supplying lower carbon energy to drive the
global economy.

This new approach aims to take account of shareholder
concerns on the level of executive pay while recognizing
the clear need for a global business like BP to attract
and retain the best talent. With those two primary
considerations in mind, my fellow board members and
I believe the new policy to be appropriate, balanced and
responsive to all those we serve as a business.

Governance and the board
Today’s world presents a range of risks – operational,
commercial, geopolitical, environmental and financial. On
the board, we aim to maintain the breadth and depth of
experience needed to fulfil our critical role of monitoring
and managing those risks, working with the executive
team.

In 2016 Nils Andersen joined us as a non-executive
director, bringing considerable insight gained in the

See Glossary.

energy, shipping and consumer goods industries. He
has led major companies, including as chief executive of
A.P. Møller-Mærsk A/S and Carlsberg A/S.

Cynthia Carroll and Andrew Shilston are standing down
as directors at the forthcoming AGM. On behalf of the
board I thank them for the substantial contributions
they have made to our work both in the board and its
committees over the years in some difficult times.

The board is proposing that Melody Meyer is elected
as a director at the AGM. Melody has had an extensive
career in the global oil and gas industry with Chevron and
will bring experience of safe and efficient operations and
world class projects. We continue to work to increase
the diversity of the board as this enhances independent
thinking and healthy challenge.

Conclusion
BP is a global business operating in over 70 countries. To
do this effectively over the long term, we need the trust
of our shareholders that we will deliver value, but also the
trust of the societies where we work – both at home and
across the world.

I believe this report, along with our Sustainability
Report, demonstrates BP’s progress in working for
all stakeholders, shareholders, customers, partners,
governments, employees and communities.

Bob and his team have guided BP from a time of crisis
in 2010 to a position where we have sound prospects
for greater value creation and growth in the years ahead.
Please join me in thanking Bob and his team for their
exceptional stewardship of BP. Thank you to the board
and to all our employees – and thank you all for your
continued support.

We are now beginning a new journey.

Carl-Henric Svanberg
Chairman
6 April 2017

$7.5bn

total dividends distributed
to BP shareholders

6.0%

ordinary shareholders
annual dividend yield

6.4%

ADS shareholders
annual dividend yield

Caption: Meeting employees
in Brazil.

More information

Corporate governance
Page 51

BP Annual Report and Form 20-F 2016Strategic report – overviewGroup chief executive’s letter

Since 2010, BP’s story has been one of recovery,
rebuilding and resilience. Now we are looking ahead
with a spirit of purpose and invention. From 2017, you
can expect a story of growth.

Caption: The BP Energy Outlook launch
at our headquarters in London, UK.

Dear fellow shareholder,

In 2016 BP started to look forward again. It may have
been one of the toughest years we have yet seen in the
business environment, with oil prices the lowest since
2004. But it was a year when we turned the challenges
into opportunities, finding new ways to compete and
grow in a fast-changing industry. Over the last six years,
we have been making BP safer, stronger and more
resilient. And in 2016 we once again began building
for growth and setting a course for a low cost, lower
carbon future.

Our results
Our top priority is always safety and in 2016 we
continued the progress made in recent years, with 80%
fewer serious incidents and a 40% lower injury rate than
in 2011. A good safety record is one sign of disciplined
operations. Another sign is reliability – and here too we
have seen improvement, with upstream plant reliability
of 95% – up from 86% in 2011 – and refining availability
of 95.3%, maintaining our strong record in recent years.

The good progress that the team made was reflected
in the financial results – with a return to headline profit
in 2016 compared with a significant headline loss
in 2015, which reflected our provisioning for Gulf of
Mexico settlements. Our underlying replacement
cost profit represents resilient performance given the
environment of low oil and gas prices and weak refining
margins. Importantly, operating cash flow in 2016 was
robust at $17.6 billion, excluding the Gulf of Mexico oil
spill payments.a Net cash provided by our operating
activities was $10.7 billion after payments for the oil spill
of $6.9 billion.

The work we have done to reduce capital spending and
costs played a large part in these results. More than two
years ago we recognized that energy prices could be
‘lower for longer’. Since then, we have been dedicated to
changing the way we work, putting in place cost savings
and efficiencies that can be sustained. As a result, our
2016 capital spend was significantly lower than peak
levels in 2013. Not only did we meet our 2017 target for
cash cost reduction – we did so a year ahead of schedule.

Capital discipline is not only about reducing spending,
but ensuring that the money we continue to invest is
spent well. One example in 2016 was the sanction of
the second phase of our Mad Dog operation in the US
Gulf of Mexico at a budget of $9 billion – less than half
the original estimate. This helps make this project highly
competitive – even in a lower oil price environment.

I am pleased to report that the major liabilities from the
Deepwater Horizon accident have been resolved – with
most of the outstanding governmental and commercial
claims clarified. Cash payments were around $7 billion
in 2016 which we expect to fall to $4.5-5.5 billion in
2017, $2 billion in 2018 and a little over $1 billion per
year thereafter. Our disciplined financial framework
can accommodate these outflows and, with this
resolution, our management team can focus with greater
confidence on the future.

a This sentence 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 2016Our portfolio
We started the year with a goal to increase production
from new projects by 800,000 barrels a day by 2020.
During 2016 we remained on track for that goal, and we
have increased our ambition to over a million barrels a day
by 2021. Given the competitive environment, this goal
goes hand in hand with a disciplined focus on costs.

In the Upstream, we launched six major project
start-ups, from Algeria to the Gulf of Mexico, and
made final investment decisions on a further five. We
are maintaining that momentum in 2017 with more
significant start-ups scheduled – including the Quad 204
development in the UK, the giant Khazzan field in Oman
and the West Nile Delta project in Egypt. These projects
bring us significant reserves, flowing supplies and lower
our per unit cost structure. They reposition our portfolio
for the future.

The Downstream has continued to improve performance
and grow with earnings up more than 25% compared
with 2014, despite lower industry refining margins. We
have enhanced our retail offer to customers – rolling out
our new fuels with ACTIVE technology in 13 countries
and building great retail partnerships such as with M&S
in the UK, REWE in Germany and, subject to regulatory
approvals, Woolworths in Australia. Plus, our partnership
with Fulcrum BioEnergy should help bring low carbon jet
fuel to the market at scale.

We have announced a number of strategic additions
to our portfolio. We broadened our positions in world-
class gas fields: in the West African basin through
an agreement with Kosmos Energy; in Egypt’s Zohr
field, thought to be the largest discovered in the
Mediterranean; and in Oman’s Khazzan development,
a giant project that has now become even bigger.
These underline our focus on gas, the fastest growing
hydrocarbon fuel with the lowest carbon content.

We have also been innovative in terms of business
models. In Abu Dhabi, we concluded an agreement to
renew an onshore oil concession, stretching to 2050, in
exchange for a 2% stake in BP. We have operated there
for 75 years and this transaction underscores the value
of long-term relationships. In Norway, we combined
Det norske’s nimble business practices, Aker’s industrial
experience and our global scale expertise to form Aker
BP – the country’s largest independent oil company.
This gives us access to substantive offshore oil and gas
resources as well as dividends for shareholders.

Putting all these initiatives together, we are creating
a substantial core of long-term, cost-efficient major
projects that can deliver material operating cash flow and
earnings for decades to come.

See Glossary.

Our future
This was also a year when we set out our strategic
priorities for the longer term. They are rooted in society’s
need to use more energy – bringing heat, light and
mobility to millions of people – while positioning BP for
a lower carbon world. These priorities will help us drive
progress and respond with agility to external changes
– whether in supply and demand, oil and gas prices, in
environmental policy or in technology.

Competitive upstream portfolio: we will expand the gas
portfolio alongside lower cost oil production, managing
these cost-effectively.

Market-led Downstream: we will provide a range of fuels
and lubricants that help make vehicles more efficient and
grow our fuels marketing and lubricants businesses.

Low carbon and venturing: we will broaden our
renewable energy and low carbon businesses
through reinvestment in the current portfolio, build a
dynamic venturing arm, and further our work in tackling
climate change.

Modernizing the whole group: we will be deploying
advanced technologies such as robotics and big data
analytics to improve and simplify our processes – as well
as using our trading expertise to maximize the value from
our assets.

I am extremely proud of the global BP team. Without the
women and men of BP, we would not have been able to
preserve and transform the business over the past six
years. I am grateful to our partners, host governments,
and other stakeholders who have stood by us as we have
stabilized BP and built up our resilience. And I say thank
you, to you, our shareholders who have afforded us the
time and support to take the actions needed to restore
BP to a position of strength from which we can grow and
prosper in the years ahead.

Since 2010, BP’s story has been one of recovery,
rebuilding and resilience. Now we are increasingly
looking ahead with a spirit of purpose and invention.
From 2017, you can expect a story of growth.

Bob Dudley
Group chief executive
6 April 2017

95.3%

2016 refining
availability

95%

Upstream BP-operated
plant reliability

Caption: Speaking with
investors at the field trip in
Baku, Azerbaijan.

More information

Business model
Page 10

Strategy
Page 14

Performance
Page 21

BP Annual Report and Form 20-F 2016Strategic report – overviewThe changing world of energy

The global energy landscape is changing.
Traditional centres of demand are being overtaken by
fast-growing emerging markets. The energy mix is
shifting, driven by technological improvements and
environmental concerns.

In summary

World economy anticipated to almost double in next 20 years.

World demand for energy expected to grow by around 30%.

Market gradually readjusting, as both supply and demand respond
to lower oil prices.

Diverse mix of fuels and technologies needed to meet demand
and climate change concerns.

Lower oil price environment
Oil prices have been substantially lower since 2014,
primarily due to oversupply. The market is gradually
readjusting, as both demand and supply respond to lower
prices. However, the high level of oil inventories suggests
this adjustment is likely to take some time.

In line with our refreshed strategy, we test our
investments against a range of oil and gas prices to check
their profitability over the long term. We take into account
current price levels and our long-term outlook.

Importantly, the break-even price of many of our
investments is going down as BP and industry suppliers
reduce costs to meet market conditions.

Energy consumption by region
(billion tonnes of oil equivalent)

2035

2015

1995

Other OECD
China

India

Other non-OECD

European Union

Growing demand for energy
Affordable energy is essential for economic prosperity.
Energy provides heat and light for homes, fuel for
transportation and power for industry. And everyday
objects – from plastics to fabrics – are derived from oil.

We expect world demand for energy to increase by
around 30% between 2015 and 2035 – largely driven by
rising incomes in emerging economies. The extent of this
increase is being curbed by gains in energy efficiency,
as there is greater attention around the world on using
energy more sustainably.

Energy mix is shifting
New technologies and consumer preferences for low
carbon energy are leading to changes in the fuel mix,
resulting in a gradual decarbonization. Renewables are
the fastest-growing energy source. They are expected to
increase at around 7% a year and account for 40% of the
growth in power generation over the next two decades.
Renewables currently contribute around 3% of total
global energy demand, and we estimate that, as a result
of rapid improvements in their competitiveness, they will
contribute around 10% by 2035.

Over the same period, we think oil and natural gas are
likely to continue to play a significant part in meeting
demand for energy. They currently account for around
56% of total energy consumption.

By 2035 we think oil will have around a 29% share,
with annual growth slowing down over this period.
Meanwhile we believe the share of gas will go up slightly
to 25% of global energy, placing it ahead of coal and not
far behind oil.

BP is gearing up to meet this shifting demand by
increasing its gas and renewables activities.

Main image: Sherbino wind farm
in Pecos County, Texas.

Inset image: Service station
in Chippenham, UK, selling
our latest fuels with ACTIVE
technology.

BP Annual Report and Form 20-F 2016

Advances in technology
Emerging technologies – such as improved batteries,
solar conversion, electricity storage and autonomous
vehicles – are accelerating the energy transition. For
example, the base case scenario in our Energy Outlook
suggests that the use of electric vehicles will grow
almost one hundred-fold by 2035. That means that about
6% of the cars on the road would be electric, with a
reduction in total oil demand of around one million barrels
a day. However, a faster mobility revolution – including
car sharing, ride pooling, autonomous vehicles and
electric cars – could reduce oil demand by several times
that amount.

Our Technology Outlook shows how technology can play
a major role in meeting the energy challenge by widening
energy resource choices, transforming the power sector,
improving transport efficiency and helping to address
climate concerns out to 2050.

We prioritize certain new technologies for in-depth
analysis – based on their fit with our strategy and how
soon and likely we think they are to break through
technological and commercial barriers. We also invest
in start-up companies to understand and participate in
these potentially transformational technologies. See
page 12.

Emerging greenhouse gas policy
and regulation
Governments are putting in place taxes, carbon trading
schemes and other measures to limit greenhouse gas
(GHG) emissions. We expect around two-thirds of BP’s
direct emissions will be in countries subject to emissions
and carbon policies by 2020.

To help anticipate greater regulatory requirements for
GHG emissions, we factor a carbon cost into our own
investment decisions and engineering designs for large
new projects and those for which emissions costs
would be a material part of the project. In industrialized
countries, this is currently $40 per tonne of carbon
dioxide equivalent, and we also stress test at a carbon
price of $80 per tonne.

Our carbon cost, along with energy efficiency
considerations, encourages projects to be set up in
a way that will have lower GHG emissions.

BP Energy Outlook provides
our projections of future energy
trends and factors that could
affect them out to 2035.

See bp.com/energyoutlook

See bp.com/technologyoutlook

More information

Challenging global energy markets
Page 20

Our strategy
Page 14

See bp.com/sustainability for
performance data, case studies
and information on our approach
to managing our sustainability
impacts.

Change in CO2

emissions
from 2015

32%

12%

13%

A changing energy mix

Energy consumption – billion tonnes of oil equivalenta

2035 Even faster transition

2035 Faster transition

2035 Base case

2015 Actual energy mix

%
6
2

%
8
2

%
9
2

%
2
3

%
3
1

%
5
2

%
3
2

%
2
2

%
4
2

%
3
2

%
9

%
8

%
8
1

%
6
1

%
3
2

%
9
2

%
3

%
7

%
4

%
8

%
7

%
0
1

%
7

%
5

Oil

Gas

Coal

Renewables

Hydro

Nuclear

a The sum of the fuel shares may not equal 100% due to rounding.

Energy outlook
The three scenarios reflect
different assumptions about the
pace of the energy transition
due to factors such as policy and
consumer behaviour.

Base case
This scenario outlines our
view of the most likely path for
energy to 2035. The growing
world economy will require
more energy but consumption
will increase less quickly than in
the past.

Faster transition
This scenario sees carbon prices
in leading economies rise to
$100/tonne by 2035 and policy
interventions encourage more
rapid efficiency gains and fuel
switching.

Even faster transition
This scenario matches the path
of the International Energy
Agency’s ‘450 scenario’,
which aims to limit the global
temperature rise to 2ºC.

BP Annual Report and Form 20-F 2016Strategic report – overview

How we run our business

From the deep sea to the desert,
from rigs to retail, we deliver energy
products and services to people
around the world. We provide
customers with fuel for transport,
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 diverse portfolio is balanced across
businesses, resource types and geographies.
Having upstream and downstream
businesses, along with well-established
trading capabilities, helps to mitigate the
impact of lower oil and gas prices. Our
geographic reach gives us access to growing
markets and new resources, as well as
diversifying exposure to geopolitical events.

Our role in society

The energy we produce helps to support
economic growth and improve quality of
life for millions of people. We strive to be
a world-class operator, a responsible
corporate citizen and a good employer.

We believe that the societies and
communities we work in should benefit
from our presence. In supplying energy we
contribute to economies around the world
by employing local staff, helping to develop
national and local suppliers, and through the
taxes we pay to governments. Additionally,
we aim to create meaningful and sustainable
impacts in those communities through our
social investments.

$11.2bn

employee wages and benefits

$2.2bn

taxes paid to governments –
comprising income and
production taxes

$7.5bn

total dividends distributed to BP
shareholders

bp.com/sustainability

10
10

BP Annual Report and Form 20-F 2016

Enabling our business model

Safe and reliable operations

Talented people

We strive to create and maintain a safe
operating culture where safety is front and
centre. This is not only safer for people
and the environment – it also improves the
reliability of our assets.

We work to attract, motivate, develop and
retain the best talent the world offers – our
performance and ability to thrive globally
depends on it.

See Safety on page 40.

See People on page 46.

Finding oil and gas

Developing and extracting oil and gas

Creating shareholder value

Finding oil and gas

New access allows us to renew our portfolio,
discover additional resources and replenish
our development options. We focus our
exploration activities in the areas that are
competitive in the portfolio. We develop and
use technology to reduce costs and risks.

Developing and extracting
oil and gas

We create value by seeking to progress
hydrocarbon resources and turn them into
proved reserves, or sell them on if they do not
fit with our strategic priorities. We develop
and produce the resources that meet our
return threshold, which we then sell to the
market or distribute to our downstream
facilities. Our upstream pipeline of future

projects gives us choice about which we
pursue – see page 28.

We also seek to grow or extend the life of
existing fields and are using new business
models to increase value. Our US Lower 48
onshore business and Aker BP in Norway (see
page 26) are two examples of how we’ve used
innovative new business models in response to
the competitive environment.

Transporting and trading

We move oil and gas through pipelines and
by ship, truck and rail. We also trade a variety
of products including oil, natural gas, liquefied
natural gas, power and currencies. Our traders
complete around 550,000 transactions and
serve more than 12,000 customers across
some 140 countries in a year.

BP Annual Report and Form 20-F 2016Technology, innovation and venturing

Partnerships and collaboration

Governance and oversight

New technologies are enabling us to produce
energy safely and more efficiently. We
selectively research and invest in areas with
the potential to add greatest value to our
business now and in the future.

We aim to build enduring relationships
with governments, customers, partners,
suppliers and communities in the countries
where we operate.

Our risk management systems and policy
provide a consistent and clear framework
for managing and reporting risks. The board
regularly reviews how we identify, evaluate
and manage risks.

See Using technology on page 12.

See Rosneft on page 35.

See How we manage risk on page 47.

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Transporting and trading

Manufacturing

Marketing fuels and products

Generating renewable energy

We use our market intelligence to analyse
supply and demand for commodities across
our global network. This helps us deliver
what the market needs, when it needs it,
identify the best markets for BP’s crude
oil, source optimal raw materials for our
refineries and provide competitive supply
for our marketing businesses.

Manufacturing and marketing
fuels and products

We produce refined petroleum products at
our refineries and supply distinctive fuel and
convenience retail services to consumers.
Our advantaged infrastructure, logistics
network and key partnerships help us to have
differentiated fuels businesses and deliver
compelling customer offers.

Our lubricants business has premium
brands and access to growth markets. It
also leverages technology and customer
relationships, all of which we believe gives
us competitive advantage. We serve
automotive, industrial, marine and energy
markets across the world.

And in petrochemicals our proprietary
technology solutions deliver leading cost
positions compared to our competitors. In
addition to our own petrochemicals plants,
we work with partners and license our
technology to third parties.

one of the world’s most sustainable and
advantaged feedstocks to produce both
low carbon ethanol and low carbon power.

We provide renewable power through
our significant interests in onshore wind
energy in the US. We develop and deploy
technology in our wind business to drive
efficiency and capacity.

Generating renewable energy

More information

We have the largest operated renewables
business among our oil and gas peers. We
operate a biofuels business in Brazil, using

Upstream
Page 24

Downstream
Page 30

Alternative energy
Page 38

BP Annual Report and Form 20-F 2016
BP Annual Report and Form 20-F 2016

11
11

Using technology

Developments in technology will shape and
influence the way we identify, extract, convert, store
and ultimately consume energy in the future.

Our approach is not about trying to do everything, but to focus on
the areas that have the greatest potential value to our business now
and in the future.

We focus our activities on:
• managing safety and operational risk
• capturing business value
• competitively differentiating BP from others.

The right technology is central to the safety and reliability of our
operations. This covers everything from assessment and management
of technical risk to maximizing our businesses efficiency and
performance. It helps us to grow value through innovation, acquisition
of competitive new capabilities and application of best practice.

In Upstream, this technology investment also supports business
strategy by focusing on increased recovery and gaining new access.
And in Downstream we develop and apply technology that enhances
operational integrity, boosts conversion efficiency or reduces CO2
emissions in some of our operations and provides high-performance
products for our customers.

We have scientists and technologists at seven major technology
centres in the US, UK and Germany. BP and its subsidiaries hold
more than 3,800 granted patents and pending patent applications
throughout the world. In 2016 we invested $400 million in research
and development (2015 $418 million, 2014 $663 million). The
reduction was largely due to halting major conversion technology
programmes in Downstream and biofuels.

Around the world, BP engineers are now using the ‘big data’ Argus
platform to make critical decisions about wells, reservoirs and fields
with state-of-the-art analytical tools that draw on historical and
real-time data points. With these new capabilities, well-sensor data
is being made available to engineers and operators within seconds
for monitoring, analysis and value optimization.

BP is partnering with others to understand and develop solutions for
the future including sustainable mobility, carbon management, power
and storage, bio-products and digital energy.

Internal technology,
and research and
development

Academic institutions

Corporate venture capital
including partnerships
and acquisitions

Strategic alliances and
joint ventures

Licensing

Our long-term research is vital to BP’s capacity to adapt and grow.
For example, the BP Institute for Multiphase Flow at the University of
Cambridge has examined a range of complex and challenging problems
associated with the flow of matter for the past 15 years. Our research
into rock and fluid interactions has led to significant developments in
the use of low salinity water to improve oil recovery from our fields.

bp.com/technology

BP Annual Report and Form 20-F 2016

Detecting early
warning signs

When a facility is unexpectedly
out of action, production revenues
are lost and costs rise from
unscheduled maintenance. But
‘plant operations advisor’, a new
digital solution we are developing
in collaboration with GE Oil &
Gas, will help our engineers
respond to issues in real time,
reducing unplanned downtime
and improving the reliability of
operational facilities. The system

30%

faster

Improving seismic
technology

Seismic data helps us see into
reservoir rock and detect where
hydrocarbon potential may lie.
Achieving high-quality images
in difficult terrains is costly and
needs many people in the field

Keeping today’s
engines running

People are increasingly choosing to
live in cities, so roads have become
much busier – meaning repetitive
stopping, waiting and starting
again. In fact, independent global
research shows that drivers spend
up to a third of urban journeys idling
– and slowly, but permanently,
this wears away critical engine
parts. That’s why we’ve launched
new engine oils containing
our latest patented molecules,
designed for the needs of today’s
engines. Castrol MAGNATEC with

Piloting in the
Gulf of Mexico

identifies early warning signs of
potential performance problems.
It gathers machinery and plant
data, analyses it and brings it all to
a single screen so that engineers
can troubleshoot quickly and
resolve potential issues. We are
now piloting the system at an
offshore operating hub in the Gulf
of Mexico.

with existing technology. In
partnership with Rosneft and
Schlumberger’s WesternGeco,
we are developing innovative
technologies to improve our
surveys with faster, better-
quality data, captured at a lower
cost with less risk. Our project
has the potential to expand
the industry’s ability to image
the subsurface, especially in
challenging land environments
across the world – and it also
offers environmental and safety
benefits when working in
extreme climates and areas that
are difficult to access.

Protecting engines for

20 years

DUALOCK contains molecules that
lock together to form a powerful
layer of engine protection. We’ve
been helping to protect engines
worldwide against warm-up wear
for 20 years. Now our unique
DUALOCK technology builds on
that by reducing both warm-up and
stop-start wear by up to 50%.

BP Annual Report and Form 20-F 2016
Working smarter

We have been reshaping our
portfolio for some years, with a
focus on achieving operational
excellence to grow margins.

We seek to get more from our existing
assets and capture value from each dollar
we spend. We encourage everyone at BP
to find and implement smarter ways of
working, without compromising safety.
From small and simple ideas to large-scale
deployment of tools – like Argus, which has

optimized monitoring and analysis for 99.5% of
our wells (see page 12), our people are helping
to make a positive difference to our operations.

In the Upstream we also launched
a modernization and transformation
programme to find ways to improve flexibility,
embrace digitization and drive capital and
operational performance. This includes a
series of online events to allow employees
to offer ideas on how we can simplify and
improve many of our processes and
ways of working.

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A lot for less

Less data, more know-how

Each year we buy an annual supply of
caustic soda for use at Cherry Point refinery.
To help achieve competitive pricing for this
product we introduced a fair and transparent
reverse auction – where sellers compete
to obtain our business. Compared with
the standard purchase prices offered to
us, the auction generated savings of more
than $250,000 for this one commodity in a
challenging supply market. We now aim to
use reverse auctions more widely in markets
where the level of competition lends itself to
this approach.

Before beginning seismic acquisition in the
shallow water area around the Absheron
Peninsula in the Azerbaijani Caspian Sea,
a subsea hazard identification survey was
needed. This process required a lot of data
collection for analysis and processing –
causing a backlog that was costing time and
money. We assessed this and discovered time
was being wasted gathering and analysing
data, regardless of height from the seabed,
when we only needed to identify targets
with heights greater than half a metre. By
reassessing the survey’s scope with the
contractor and establishing a new process
to only capture what was needed, we saved
around $750,000.

Improving competitiveness

In the UK we have historically supplied fuels
to our retail sites using our own in-house
transportation fleet. After a strategic review
to continue to improve competitiveness, we
transferred all our UK secondary transport
activities including scheduling, dispatching
and delivery operations to Hoyer – a leading
large-scale logistics service provider. This
change further strengthens our business by
giving us access to a cost-effective and
flexible service from a professional
international haulier with a reliable safety
track record.

Getting onboard savings

Lightening the load

To access a rig in Trinidad, operators used
complex scaffolding that took around 11
days to set up. By replacing this with a
fixed-structure platform we decreased
set up time by nine days and reduced risk
of joint failure by removing scaffolding
connections. This has made significant
savings in rig costs and is already being
reused to achieve further savings at other
facilities in Trinidad.

As part of our review of rental equipment
at the PSVM development in Angola, we
removed a number of items – like tool boxes,
gas racks and welding machines – that were
being held on the vessel but not used. This
has already delivered equipment savings of
$750,000 in 2016 and eliminated man hours
required for maintaining and inspecting the
equipment. We are now looking for similar
opportunities to review excess equipment
and inventories elsewhere.

BP Annual Report and Form 20-F 2016
BP Annual Report and Form 20-F 2016

13
13

Our strategy

Fit for the future

Our industry is changing at a pace not seen in
decades. All forms of energy – fossil fuels and
renewables – are becoming more abundant and less
costly. Through new technologies, energy will be
produced more efficiently and in new ways, helping
to meet the expected rise in demand. And the world
is working towards a lower carbon future.

We are evolving our strategy – allowing us to be
competitive in a time when prices, policy, technology
and customer preferences are changing.

Our strategic priorities help us to deliver heat, light
and mobility solutions for a changing world.

How we do this

2016 activities

BP Annual Report and Form 20-F 2016

Shift to gas and
advantaged oil in the
upstream

Invest in new large-scale gas
projects, pursue quality oil projects
in core basins and seek out new
opportunities in selected regions.

Around 75% of our planned
start-ups by 2021 are in gas
projects.

All of our planned oil start-ups out
to 2021 are lower cost or around
our existing basins.

Maximize recovery, manage decline
and extend the life of our existing oil
and gas fields.

Optimize our portfolio by making
investments and divestments
to deliver long-term value, with
the potential to start increasing
earnings or cash flow within a short
time frame.

We renewed our interest in the Abu Dhabi
ADCO onshore concession and signed a
letter of intent for the future development of
the Azeri-Chirag-Gunashli field – boosting
our lower-cost oil production for decades to
come. We also made deals to expand our
gas exposure in China, Egypt, Indonesia,
Mauritania and Senegal, and Oman.

Read more in Downstream on page 30.

a Subject to regulatory approval.

Read about our activities in Using
technology on page 12 and
Alternative energy on page 38.

Read more in Group performance
on page 21.

BP Annual Report and Form 20-F 2016

The foundations for strong performance

Safe and reliable operations, a balanced portfolio and a focus
on returns provide the platform for growth which is critical to
the successful delivery of our strategy.

These build on our group business model: having the right
people, partnerships, processes and technology in place to
deliver value across all our activities.

Safe, reliable and efficient execution
Operational excellence is essential to our success.
Good safety leads to reliable operation of our assets,
greater efficiency and ultimately better financial results.
Our operating management system promotes
continuous improvement and systematic ways of
working. And, we are using technology to produce
energy more safely and efficiently.

Operating reliability and availability

100%

94.8%

95%

93%

92%

88%

2012

95%

Refining
availability

Upstream
operated plant
reliability

2016

Distinctive portfolio with optionality
We benefit from having upstream, downstream and
alternative energy businesses – challenges in one part of
the group can create opportunities in another. Around the
world, we are investing in upstream projects – expected
to deliver operating cash marginsa 35% better than 2015
levels. We are driving sustainable competitiveness in our
downstream business, with a focus on customers, cost
efficiency and margin capture.

Our well-established oil and gas trading function can
generate value by providing the link between our
businesses and third parties. And our equity interest
in Rosneft gives us access to one of the largest and
lowest-cost hydrocarbon resource bases in the world.
a Based on 2015 oil prices.

Disciplined growth

start-ups under
construction

1 million +
production of additional
barrels of oil equivalent
per day expected
by 2021

Personal and process safety performance

2016

2021

100%

2012

BP Annual Report and Form 20-F 2016

Marketing and customer focus

Retail convenience partnerships

• Castrol EDGE
• Castrol GTX
• Castrol MAGNATEC

• M&S Simply Food®
• REWE to go®
• Pick n Pay®

Lubricants

Fuels

• BP
• Arco
• Aral
• Air BP

Down

40%

Down

49%

Process
safety events

Recordable injury
frequency

2016

More than 50% of downstream profits are from marketing activities.

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Focused on delivering competitive returns
In 2014 we set out our financial framework in response
to the sharp decline in the oil price. The framework
underpins our commitment to sustain the dividend for our
shareholders. We have been meeting those expectations
each year – and even reaching our cash cost reduction
target a year early. We also reduced our upstream and
downstream headcount by a total of 6,000 in 2016 – a
reduction of 17% since 2014.

We have now updated and extended the framework out
to 2021. We expect our strong balance sheet to be able
to deal with any near-term volatility. Beyond that, we
aim to increase operating cash flow – from our planned
upstream start-ups and growth in the downstream. With
a constant capital frame we intend to grow sustainable
free cash flow and distributions to shareholders in the
long term.

Principle

Optimize capital
expenditure

Our financial framework
underpins our commitment
to sustain the dividend for
our shareholders.

Make selective
divestments

Payments related to the
Gulf of Mexico oil spill

Maintain flexibility
around gearing

2016 organic capital
expenditure was $16 billion*
– after excluding the
consideration for the renewal of
10% of the Abu Dhabi ADCO
onshore oil concession.

This was well below our original
guidance of $17-19 billion.

$3.2 billiona achieved in 2016.

This was within the expected
guidance of $3-5 billion for
the year.

2016 payments totalled
$6.9 billion, reflecting faster
resolution of outstanding
claims.

Gearing at the end of 2016
was 26.8%**.

This was within our target
range of 20-30%.

Looking ahead – 2018 to 2021

We expect organic capital
expenditure of $15-17 billion.

We expect organic capital
expenditure of $15-17 billion
per year.

We expect divestments of
$4.5-5.5 billion.

$2-3 billion of divestments
as a result of active portfolio
management.

We expect $4.5-5.5 billion
of cash payments.

Around $2 billion in 2018 and
moving to annual payments of just
over $1 billion from 2019 onwards.

Within the 20-30% band.

Group ROACE

ROACE was 2.8%*** in 2016.

–

We are aiming to exceed 10%
by 2021 at real oil prices around
$55/barrel.

a Includes $0.6 billion for the sale of 20% from our shareholding in Castrol India Limited.

Balancing our sources and uses of cash

We aim for our operating cash flow (excluding
payments related to the Gulf of Mexico oil spill)
to cover our dividend payments and organic
capital expenditure .

Nearest GAAP equivalent measures
*
Additions to non-current assets: $21 billion.
** Ratio of gross debt to gross debt plus equity: 37.6%.
*** Numerator: Profit attributable to BP shareholders $115 million;

Denominator: Average capital employed $153 billion.

See Glossary.

BP Annual Report and Form 20-F 2016

2016 achievement2017 guidance3030201525105201525105SourcesSourcesUses2016Capital investment – investing activitiesDividends paidOperating cash ﬂow – Gulf of Mexico oil spillUsesSources2015UsesOperating cash ﬂow – rest of groupDisposal proceeds – investing activities For the year ended 31 December ($ billion)

Measuring our 2016 progress

Underlying replacement cost proﬁt
($ billion)

2016 REM

Operating cash ﬂow ($ billion)
2016 REM

2016

2015

2014

2013

2012

(6.5)

0.1

2.6

5.9

3.8

12.1

13.4

11.0

23.5

-10

-5

17.1
20

Proﬁt (loss) for the year
Underlying RC proﬁt for the year

2016

2015

2014

2013

2012

10.7

17.6

20.3

19.1

32.8
32.8

21.2
21.1

22.9

20.5

Operating cash ﬂow excluding amounts related to the
Gulf of Mexico oil spilla
Operating cash ﬂow

is a useful measure for investors because

Underlying RC profit
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.

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.

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 .

2016 performance Profit for the year reflected lower charges for
the Gulf of Mexico oil spill than 2015. The reduction in underlying
RC profit compared with 2015 was mainly due to lower oil and
gas prices and the weaker refining environment, see pages 24
and 30.

2016 performance Operating cash flow of $10.7 billion was
lower, mainly due to higher Gulf of Mexico oil spill payments
which amounted to $6.9 billion in 2016. Operating cash flow was
also impacted by lower realizations, partly offset by lower costs
and working capital effects.

a These bars on the chart do not form part of BP’s Annual
Report on Form 20-F as filed with the SEC.

Major project delivery
2016 REM

Production (mboe/d)

2016

2015

2014

2013

2012

2016

2015

2014

2013

2012

3,141

3,268

3,239

3,230

3,331

3,100

3,200

3,300

3,400

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.

2016 performance We started up two major projects in
Algeria, two in the Gulf of Mexico, and one each in Alaska
and Angola.

We report production of crude oil, condensate, natural gas
liquids (NGLs), natural bitumen and natural gas on a volume per
day basis for our subsidiaries and equity-accounted entities.
Natural gas is converted to barrels of oil equivalent at 5,800
standard cubic feet of natural gas = 1 boe.

A minor adjustment has been made to 2015 and 2014, see
page 25 for further information.

2016 performance BP’s total reported production including
Upstream and Rosneft segments was slightly higher than
in 2015.

Tier 1 process safety eventsb
2016 REM

Loss of primary containmentb
2016 REM

2016

2015

2014

2013

2012

2016

2015

2014

2013

2012

233

275

208

235

246

286

261

292
300

400

100

200

We report tier 1 process safety events which are losses of
primary containment of greatest consequence – causing harm
to a member of the workforce, costly damage to equipment or
exceeding defined quantities.

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.

2016 performance The number of tier 1 process safety
events has decreased since 2012. We believe our systematic
approach to safety management and assurance is contributing
to improved performance over the long term and will maintain
our focus in these areas.

2016 performance We saw an increase of LOPCs in 2016,
partly due to harsher winter operating conditions in our
unconventional gas operations in the US. Figures for 2014 to
2016 include increased reporting due to the introduction of
enhanced automated monitoring for remote sites in our US
Lower 48 business. Using a like-for-like approach with previous
years’ reporting, our LOPC figure is 233 (2015 208, 2014 246).

We assess our performance
across a wide range of measures
and indicators.

Our key performance indicators (KPIs) help
the board and executive management assess
performance against our strategic priorities
and business plans. 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.

Remuneration

To help align the focus of our board and
executive management with the interests of
our shareholders, certain measures are used
for executive remuneration. Overall annual
bonuses and performance shares for 2016 are
all based on performance against measures
and targets linked directly to the strategy and
KPIs.

Changes to KPIs
We have updated some of our KPIs this year to
better align to our evolved strategy and future
remuneration policy.

• We’ve added return on average capital

employed and upstream unit production
costs as these will be important measures
for assessing future performance and pay
outcomes.

• We’re showing replacement cost profit at

group level rather than on a per-share basis
as this aligns with the measure used for
executive remuneration.

• We’ve removed gearing, or net debt ratio, as
a group KPI but will continue to report it in
Group performance.

Looking ahead
The KPIs associated with our 2017-2019
remuneration policy can be found on
page 104. We’ll disclose our performance
against these in our 2017 report.

2016 REM

KPIs used to determine
2016 remuneration.

More information

Directors’ remuneration
Page 80

BP Annual Report and Form 20-F 2016
Total shareholder return (%)

Return on average capital employed (%)

2016 REM

(12.8)

(8.3)

(16.5)

(11.6)

2016

2015

2014

2013

2012

14.7
14.0

4.5
2.6

29.0

55.5

2016

2015

2014

2013

2012

2.8

5.5

9.6

10.2

13.4

Reserves replacement ratio (%)
2016 REM

2016

2015

2014

2013

2012

109

77
80

100

120

140

129

-20

ADS basis

Ordinary share basis

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.

2016 performance Increased TSR reflects share price growth
in 2016, as well as maintaining the dividend per share.

Return on average capital employed (ROACE) gives an indication
of a company’s capital efficiency, dividing the underlying RC
profit after adding back net interest by average capital employed,
excluding cash and goodwill. See page 285 for more information
including the nearest GAAP equivalent data.

For the past few years, ROACE has been lower in the oil and
gas sector, due to the impact of lower oil prices on earnings and
the capital overhang of investments made during the preceding
period of $100 per barrel oil prices.

2016 performance The 2016 reduction in ROACE is mainly due
to weaker oil and gas prices and refining margins, partly offset by
lower costs.

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.

2016 performance This year’s reserves replacement ratio was
higher than our five-year average primarily as a result of the Abu
Dhabi onshore concession renewal. See page 244 for more
information.

Upstream unit production costs ($/boe)

Reﬁning availability (%)

Reported recordable injury frequencyb

2016

2015

2014

2013

2012

8.5

10.5

12.8

13.2

12.5

2016

2015

2014

2013

2012

95.3

94.7

94.9

95.3

94.8

2016 REM

2016

2015

2014

2013

2012

0.21

0.24

0.2

0.31

0.35
0.4

0.6

The upstream unit production cost indicator shows how
supply chain, headcount and scope optimization impact cost
efficiency.

2016 performance The lower unit production costs in 2016
reflect increased efficiency, reduced headcount, as well as
deflation. This continues the cost reduction trend, down by
over 35% since 2013.

Greenhouse gas emissions
(million tonnes of CO2 equivalent)

2016

2015

2014

2013

2012

50.1

49.0

48.7

50.3

20
20

40
40

59.8

We provide data on greenhouse gas (GHG) emissions
material to our business on a carbon dioxide-equivalent basis.
This includes carbon dioxide (CO2) and methane for direct
emissions. 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 for the relevant
periods.

Minor adjustments have been made to the 2014 and 2015
figures. See page 43.

2016 performance The increase in our reported emissions
is primarily due to operational variations such as returning
to normal operations after planned shutdowns and start-up
activities in Canada and Angola.

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.

2016 performance Refining availability increased by 0.6%
from 2015 to 95.3%, reflecting strong operational performance
across our portfolio. This performance is underpinned by our
global reliability improvement programme which provides our
refineries with a more structured and systematic approach to
improving availability.

Reported recordable injury frequency (RIF) measures the
number of reported work-related employee and contractor
incidents that result in a fatality or injury per 200,000 hours
worked.

2016 performance Our workforce RIF has improved steadily
over five years and is also reflected in our other occupational
safety metrics. While this is encouraging, continued vigilance
is needed. For detail on employee and contractor safety against
industry benchmarks, see page 40.

b 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.

Group priorities indexc (%)

Diversity and inclusionc (%)

2016

2015

2014

2013

2012

We track how engaged our employees are with our strategic
priorities using our group priorities index. This is derived from
survey questions about their perceptions of BP and how it is
managed in terms of leadership and standards.

2016 performance Our group priorities engagement
measure increased in 2016. Confidence in the future of
BP also rose to 64% (2015 58%, 2014 63%).

c Relates to BP employees.

2016

2015

2014

2013

2012

Women

Non UK/US

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.

2016 performance The percentage of our group leaders who
are women or non-UK/US rose. We remain committed to
our aim that women will represent at least 25% of our group
leaders by 2020.

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – strategyChallenging global energy markets

Oil prices have been substantially lower since 2014.
The market is gradually readjusting, as both demand
and supply respond to lower prices. However, the high
level of oil inventories suggests this adjustment is likely
to take some time.

Brent dated average
crude oil prices
($/barrel)

2014

The world economy remained weak in 2016, with
global GDP growth at 2.3%. This was significantly
lower than the average of nearly 3% over the past 20
years. Economic growth in the OECD slowed to 1.7%,
(2.3% 2015) – partly due to weak global trade and lower
business investment in the US.

In contrast, the non-OECD economy grew by 3.4%
(3.3% 2015). This follows six years of declining growth
and is partly driven by relative stability in China and
improvements in Russia and Brazil.

$98.95

Oil
Crude oil prices ($/bbl – quarterly average)

150

120

2016

Brent dated

Prices
Dated Brent crude oil prices averaged $43.73 per barrel
in 2016 – a further drop from the 2015 average of $52.39.
But prices recovered over the year, rising from around
$30 per barrel in January to nearly $54 in December.

Consumption
Global consumption increased by 1.6 million barrels per
day (mmb/d) to 96.6mmb/d for the year (1.7%) – mostly
due to continued low oil prices.a Demand grew most
rapidly in Asia’s emerging economies, but OECD demand
also increased for the second consecutive year.

Production
Strong consumption growth outpaced growth in global
production. Non-OPEC production fell by 0.8mmb/d – the
largest drop since 1992 – driven by the collapse of drilling
in the US and a sharp decline in Chinese investment.
However, OPEC production grew by 1.2mmb/d, reaching
a record level of 39.3mmb/d, due to the recovery of
Iranian production and large increases in Saudi Arabia and
Iraq.

Inventories
Oil inventories remained high. And although data on
global inventories is not available, OECD commercial
inventories, as at 31 December, remained 290 million
barrels above the five-year average, even though they had
begun to reduce.

2015

$52.39

2016

$43.73

More information

Prices and margins
Pages 25 and 32

Natural gas
Natural gas prices ($/mmBtu – quarterly average)

07
Henry Hub

2016

Prices
Gas prices were low in all key markets in 2016 as markets
continued to adjust to the oversupply that built up during
2015, with increasing trade ensuring that the effect of
ample supplies was felt globally.

Gas prices in the US averaged $2.46 per million
British thermal units (mmBtu), slightly lower than 2015
($2.67). The Japanese spot price fell to an average of
$5.7/mmBtu in 2016 (2015 $7.4) with rising supplies in
the region outpacing growth in demand, including new
and emerging markets. The UK National Balancing Point
hub price was 34.63 pence per therm, 19% lower than in
2015 (42.61), as higher demand was easily met by rising
pipeline imports, especially from Russia.

Broad differentials between regional gas prices also
remained low, as US gas prices moved closer to Asian
and European spot prices.

Consumptionb
Global consumption grew significantly faster than in
2015. The pattern of growth across markets shifted, with
strong demand growth in the OECD and China offsetting
weakness in other markets. Gas consumption in the
power sector continued to grow globally, gaining share
from coal helped by the local production curbs in China.
And with coal production curbs in China taking hold,
the market tightened in 2016. In addition, higher
weather-related demand towards the end of the year
boosted the total annual demand.

Productionb
Total production in 2016 was similar to 2015, with strong
growth in Australia and Russia making up for declining
production in Europe where existing fields are maturing
and not being replaced.

Global LNG supply capacity expanded strongly in 2016,
following a small increase in 2015.

a From IEA Oil Market Report, February 2017 ©, OECD/IEA 2017.
b Based on BP estimates from the BP Energy Outlook.

BP Annual Report and Form 20-F 2016
Group performance

BP made good financial progress in 2016, supported
by the significant and rapid changes we have made
to our cost base. We reached our target of reducing
controllable cash costs by $7 billion a year ahead of plan.

S
t
r
a
t
e
g
c
r
e
p
o
r
t
–
p
e
r
f
o
r
m
a
n
c
e

Dr Brian Gilvary Group chief financial officer

In summary

$2.6bn

$7bn

underlying replacement
cost profit
(2015 $5.9bn)

cash cost reduction versus
2014 – the costs which we
consider to be controllable

$115m

profit attributable to BP
shareholders
(2015 $6.5bn loss)

$69m

reduction in total costsa versus
2014 – reflects an increase in
Gulf of Mexico oil spill charges
of $5.9bn, and a reduction of
$6.0bn in other costs, some
of which are not considered
controllable

Segment RC proﬁt (loss) before interest and tax
($ billion)

2016

2015

2014

(20)

(15)

(10)

(5)

Rosneft

Downstream

Upstream
Other businesses and corporate – other
Other businesses and corporate – Gulf of
Mexico oil spill
Consolidation adjustment – UPII

Group RC proﬁt (loss) before interest and tax

$ million
except per share amounts
2014
6,412

2015
(7,918)

(1,653)
3,171
(82)
(6,482)
1,889
(569)
(5,162)
15,328
(4,056)

(261)
56
5,905
40.0
26.383
20,080

18,748
710
19,458

(1,462)
(947)
(223)
3,780
6,210
(1,917)
8,073
9,132
(4,512)

(898)
341
12,136
39.0
23.850
26,492

22,892
601
23,493

2016
(430)

(1,865)
2,467
(57)
115
(1,597)
483
(999)
5,661
(2,833)

1,085
(329)
2,585
40.0
29.418
21,204

18,440
939
19,379

Financial and operating performance

Profit (loss) before interest and taxation
Finance costs and net finance expense relating to pensions

and other post-retirement benefits

Taxation
Non-controlling interests
Profit (loss) for the yearb
Inventory holding (gains) losses , before tax
Taxation charge (credit) on inventory holding gains and losses
Replacement cost profit (loss)
Net charge (credit) for non-operating items , before tax
Taxation charge (credit) on non-operating items
Net (favourable) unfavourable impact of fair value accounting

effects , before tax

Taxation charge (credit) on fair value accounting effects
Underlying replacement cost profit
Dividends paid per share – cents
– pence
Additions to non-current assetsc
Capital expenditure on an accruals basis d e
Organic capital expenditure f
Inorganic capital expenditure

Main image: A pipe rack on
board the Discoverer Luanda drill
ship, off the coast of Angola.

More information

Upstream
Page 24

Downstream
Page 30

Rosneft
Page 35

Other businesses
and corporate
Page 37

Oil and gas disclosures
for the group
Page 251

See Glossary.

a Production and manufacturing expenses and distribution and administration expenses from the income statement.
b Profit (loss) attributable to BP shareholders.
c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
d A reconciliation to GAAP information is provided on page 285.
e The definitions of capital expenditure on an accruals basis and inorganic capital expenditure have been revised to exclude asset exchanges as they are
non-cash transactions. Previously reported amounts have been amended. Previously reported amounts for organic capital expenditure are unchanged.
f 2016 includes amounts relating to the renewal of a 10% interest in the Abu Dhabi onshore oil concession for which new ordinary shares in BP were issued.

BP Annual Report and Form 20-F 2016

The profit for the year ended 31 December 2016 was $115 million,
compared with a loss of $6.5 billion in 2015. Excluding inventory holding
gains, replacement cost (RC) loss was $1.0 billion, compared with a loss
of $5.2 billion in 2015.

The net charge for non-operating items mainly relates to additional
charges for the Gulf of Mexico oil spill which are partially offset by net
impairment reversals. There were net unfavourable fair value accounting
effects. After adjusting for non-operating items and fair value accounting
effects, underlying RC profit for the year ended 31 December 2016
was $2.6 billion, a decrease of $3.3 billion compared with 2015. The
reduction was predominantly due to lower results in both the Upstream
and Downstream segments reflecting lower oil and gas prices and the
weaker refining environment (see pages 24 and 30).

Non-operating items in 2016 also include a restructuring charge of
$0.8 billion (2015 $1.1 billion), cumulative restructuring charges from
the beginning of the fourth quarter 2014 totalled $2.3 billion by the end
of 2016. Non-operating restructuring charges are expected to continue
into 2017.

The loss for the year ended 31 December 2015 was $6.5 billion,
compared with a profit of $3.8 billion in 2014. Excluding inventory
holding losses, RC loss was $5.2 billion, compared with a profit of
$8.1 billion in 2014.

After adjusting for a net charge for non-operating items, which mainly
related to the agreements in principle to settle federal, state and the vast
majority of local government claims arising from the 2010 Deepwater
Horizon accident and impairment charges; and net favourable fair
value accounting effects, underlying RC profit for the year ended 31
December 2015 was $5.9 billion, a decrease of $6.2 billion compared
with 2014. The reduction was mainly due to a significantly lower profit in
Upstream, partially offset by improved earnings from Downstream.

More information on non-operating items and fair value accounting
effects can be found on page 285. See Other businesses and corporate
on page 37 and Financial statements – Note 2 for further information on
the impact of the Gulf of Mexico oil spill on BP’s financial results.

Taxation
The credit for corporate income taxes in 2016 and 2015 reflects the
deferred tax impact of the increased provisions in respect of the Gulf
of Mexico oil spill. The effective tax rate (ETR) on the loss for the year
was 107% in 2016 and 33% in 2015; the ETR on the profit for the year
in 2014 was 19%. The ETR in 2016 and 2015 was impacted by various
one-off items.

Adjusting for inventory holding impacts, non-operating items, fair value
accounting effects and the deferred tax adjustments as a result of the
reductions in the UK North Sea supplementary charge in 2016 and 2015,
the adjusted ETR on RC profit was 23% in 2016 (2015 31%, 2014
36%). The adjusted ETR for 2016 is lower than 2015 predominantly
due to changes in the geographical mix of profits as a result of the
lower oil price and the absence of foreign exchange impacts from the
strengthening of the US dollar in 2015. The adjusted ETR for 2015
was lower than 2014 mainly due to changes in the geographical mix of
profits.

In the current environment, and reflecting the recent transaction to
renew a 10% interest in the Abu Dhabi onshore oil concession, the
adjusted ETR in 2017 is expected to be in the region of 40%.

Cash flow and net debt information

Operating cash flow excluding

amounts related to the Gulf of
Mexico oil spill

Operating cash flow
Net cash used in investing activities
Net cash provided by (used in)

2016

2015

$ million
2014

17,583
10,691
(14,753)

20,263
19,133
(17,300)

32,763
32,754
(19,574)

financing activities

1,977

(4,535)

(5,266)

Cash and cash equivalents at end

of year
Gross debt
Net debt
Gross debt to gross debt plus equity
Net debt to net

23,484
58,300
35,513
37.6%

29,763
26,389
52,854
53,168
27,158
22,646
35.1% 31.9%

debt plus equity

26.8%

21.6% 16.7%

a This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

Operating cash flow
Net cash provided by operating activities for the year ended
31 December 2016 was $8.4 billion lower than 2015. Of this amount,
$6.0 billion was a result of higher pre-tax cash outflows associated with
the Gulf of Mexico oil spill ($7.1 billion in 2016 compared with $1.1 billion
in 2015). Cash flows were impacted by the continuing low oil price
environment, with a lower average oil price in 2016 compared with
2015, working capital effects, and a reduction of $0.7 billion in income
taxes paid.

Movements in inventories and other current and non-current assets and
liabilities adversely impacted cash flow in the year by $3.2 billion. There
was an adverse impact from the Gulf of Mexico oil spill of $4.8 billion.
Other working capital effects, arising from a variety of different factors,
had a favourable impact of $1.6 billion. The group actively manages
its working capital balances to optimize cash flow, particularly in the
current lower oil price environment. Inventories increased during the
year because volumes were increased in our trading business to benefit
from market opportunities, and due to higher prices towards the end of
the year. The increase in inventory was largely offset by a corresponding
increase in payables, limiting the increase in working capital.

There was a decrease in net cash provided by operating activities of
$13.6 billion in 2015 compared with 2014 of which $1.1 billion related to
the Gulf of Mexico oil spill. This was principally a result of the lower oil
price environment, although there were benefits of reduced working
capital requirements and lower tax paid.

Net cash used in investing activities
Net cash used in investing activities for the year ended 31 December
2016 decreased by $2.5 billion compared with 2015.

The decrease mainly reflected a reduction in cash outflow in respect
of capital expenditure, including investment in joint ventures and
associates , of $2.8 billion. The decrease of $2.3 billion in 2015
compared with 2014 reflected a reduction in cash outflow in respect
of capital expenditure of $3.9 billion, partly offset by a reduction
of $0.7 billion in disposal proceeds. The reductions in cash capital
expenditure in both years reflect the group’s response to the lower oil
price environment.

There were no significant cash flows in respect of acquisitions in 2016,
2015 and 2014.

The group has had significant levels of capital investment for many
years. Cash flow in respect of capital investment, excluding acquisitions,
was $17.5 billion in 2016 (2015 $20.2 billion and 2014 $23.1 billion).
Sources of funding are fungible, but the majority of the group’s funding
requirements for new investment comes from cash generated by
existing operations.

BP Annual Report and Form 20-F 2016proceeds from financing of $3.2 billion ($4.4 billion lower net proceeds
from long-term debt offset by an increase of $1.2 billion in short-term
debt), and an increase in the total dividend paid in cash of $0.8 billion –
see below for further information.

Total dividends distributed to shareholders in 2016 were 40 cents per
share, the same as 2015 on a US dollar basis and up 11.5% in sterling
terms. This amounted to a total distribution to shareholders of $7.5 billion
(2015 $7.3 billion, 2014 $7.2 billion), of which shareholders elected to
receive $2.9 billion (2015 $0.6 billion, 2014 $1.3 billion) in shares under the
scrip dividend programme. The total amount distributed in cash amounted
to $4.6 billion during the year (2015 $6.7 billion, 2014 $5.9 billion).

Net debt
Gross debt at the end of 2016 increased by $5.1 billion from the end of
2015. The gross debt ratio at the end of 2016 increased by 2.5%. Net
debt at the end of 2016 increased by $8.4 billion from the 2015 year-end
position. The net debt ratio at the end of 2016 increased by 5.2%.

We continue to target a net debt ratio in the range of 20-30%. Net
debt and the net debt ratio are non-GAAP measures. See Financial
statements – Note 26 for gross debt, which is the nearest equivalent
measure on an IFRS basis, and for further information on net debt.

The total cash and cash equivalents at the end of 2016 were $2.9 billion
lower than 2015.

For information on financing the group’s activities, see Financial
statements – Note 28 and Liquidity and capital resources on page 242.

Group reserves and production (including Rosneft segment)

2016

2015

2014

Estimated net proved reservesa

(net of royalties)

Liquids (mmb)
Natural gas (bcf)
Total hydrocarbons (mmboe)
Of which: Equity-accounted
entitiesb

Productiona (net of royalties)
Liquids (mb/d)c
Natural gas (mmcf/d)
Total hydrocarbonsc (mboe/d)
Of which: Subsidiaries c

Equity-accounted
entitiesd

10,333
43,368
17,810

9,560
44,197
17,180

9,817
44,695
17,523

8,679

7,928

7,828

2,048
7,075
3,268
1,939

2,007
7,146
3,239
1,969

1,917
7,100
3,141
1,889

1,329

1,270

1,253

a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes BP’s share of Rosneft. See Rosneft on page 35 and Supplementary information on oil

and natural gas on page 187 for further information.

c A minor adjustment has been made to comparative periods, see page 25 for further
information.
d Includes BP’s share of Rosneft. See Rosneft on page 35 and Oil and gas disclosures for the

group on page 251 for further information.

Total hydrocarbon proved reserves at 31 December 2016, on an
oil-equivalent basis including equity-accounted entities, increased by 4%
compared with 31 December 2015. The change includes a net increase
from acquisitions and disposals of 520mmboe (decrease of 128mmboe
within our subsidiaries, increase of 648mmboe within our equity-
accounted entities). Acquisition activity in our subsidiaries occurred in
Abu Dhabi (increase of interest in ADCO concession from 9.5% to 10%)
Indonesia, the US and the UK, and divestment activity in our subsidiaries
occurred in Norway, Indonesia, Australia, Trinidad and the US. In our
equity-accounted entities the most significant items were purchases in
Russia, Norway and Venezuela.

Our total hydrocarbon production for the group was 0.9% higher
compared with 2015. The increase comprised a 1.5% decrease (0.3%
increase for liquids and 3.5% decrease for gas) for subsidiaries and a
4.7% increase (3.9% increase for liquids and 7.4% increase for gas) for
equity-accounted entities.

Driving efﬁciency

We are simplifying and modernizing the way we work in BP to
perform more efficiently in the current industry environment, and to
support strong performance and growth into the long term.

We now deliver many of the group’s business support activities –
financial reporting, supplier payment, customer order and cash
collection – from our global business services (GBS) organization.
GBS develops standard processes and procedures and uses insight
from data analytics, innovation and technology, to find ways to
improve the way we do business. This allows us to drive efficiencies
across BP, as well as offering significant economies of scale.

The service offer has recently expanded to include human resources,
tax, internal control and procurement activities, and we expect
further growth in both existing operations and new areas.

GBS has a network of nine centres, five run by BP, the others by
Accenture, with about 5,500 staff around the world. We plan to open
a new BP location in Szeged, Hungary in late 2017.

Through operating and sourcing processes more efficiently, GBS is
delivering significant value to BP.

We expect organic capital expenditure on an accruals basis to be in the
range of $15-17 billion in 2017.

Disposal proceeds for 2016, as per the cash flow statement, were
$2.6 billion (2015 $2.8 billion, 2014 $3.5 billion), including amounts
received for the sale of certain midstream assets in the Downstream
fuels business and our Decatur petrochemicals complex. In addition, in
2016 we also received $0.6 billion in relation to the sale of 20% from our
shareholding in Castrol India Limited, shown within financing activities
in the cash flow statement, giving total proceeds of $3.2 billion for the
year. In 2015 disposal proceeds included amounts received from our
Toledo refinery partner, Husky Energy, in place of capital commitments
relating to the original divestment transaction that have not been
subsequently sanctioned. We expect disposal proceeds to be in the
range of $4.5-5.5 billion in 2017.

Net cash used in ﬁnancing activities
Net cash provided by financing activities for the year ended 31
December 2016 was $2.0 billion, compared with $4.5 billion used in
2015. This was mainly the result of higher net proceeds from financing
of $3.6 billion ($4.0 billion higher net proceeds from long-term debt
offset by a decrease of $0.4 billion in short-term debt). In addition, there
was a cash inflow of $0.9 billion relating to increases in non-controlling
interests, including the sale of 20% from our shareholding in Castrol
India Limited noted above. The total dividend paid in cash in 2016 was
$2.1 billion lower than in 2015 – see below for further information.

The decrease in net cash used in financing activities of $0.7 billion in
2015 compared with 2014 reflected no share repurchases in 2015,
compared with $4.6 billion in 2014. This was largely offset by lower net

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performanceUpstream

We are building a business that is safer, more
modern and efficient, and delivering real value
and tangible growth – to 2021 and beyond.

Bernard Looney Chief executive, Upstream

In summary

71,000km2 6

new exploration access
(2015 8,000km2)

major project
start-ups
(2015 3)

successful completion
of turnarounds
(2015 15)

final investment
decisions
(2015 4)

95%

upstream BP-operated
plant reliability
(2015 95%)

2.2

million barrels of oil
equivalent per day –
hydrocarbon production
(2015 2.2mmboe/d)

Upstream proﬁtability ($ billion)

-0.5
-0.9

0.6

1.2

2016

2015

2014

2013

2012

8.9

15.2

16.7

18.3

22.5

19.4

Replacement cost (RC) proﬁt (loss) before interest and tax
Underlying RC proﬁt (loss) before interest and tax

Our business model and strategy
The Upstream segment is responsible for our activities
in oil and natural gas exploration, field development and
production, as well as midstream transportation, storage
and processing. We also market and trade natural gas,
including liquefied natural gas, power and natural gas
liquids. In 2016 our activities took place in 28 countries.

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

• 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 over the life of each field.

• 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.

• 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
across 13 regions, with support provided by global
functions in specialist areas of expertise: technology,
finance, procurement and supply chain, human
resources, information technology and legal.

The US Lower 48 continues to operate as a separate,
asset-focused, onshore business.

Our strategy is to have a balanced portfolio across the
world’s key oil and gas basins, while maintaining a focus
on capital discipline and quality execution to deliver
value. Our incumbent positions and the relationships
we hold with resource owners create both stability and
opportunity.

Our strategy is enabled by:

• A relentless focus on safety, reliability and the

systematic management of risk.

• The quality execution of our projects, our operations,

our drilling, and managing our reservoirs – the greatest
source of value and returns that we have.

• Growing value through improving returns and cash
flow. We actively manage our portfolio, divesting
where it makes sense, and pursue acquisitions where
value can be created.

• The capability of our people, who are motivated and
equipped to take on the world’s great oil and gas
challenges. We have a global workforce that is
embracing digital technology to drive improved
productivity in everything we do.

Our future growth includes an expected 800,000 barrels
of oil equivalent per day of production from new projects
by 2020, with 500,000 barrels of oil equivalent per day
of this new capacity planned to be online by end of 2017.
This, combined with our recent portfolio additions, is
expected to increase our production by around 1 million
barrels per day by 2021.

Main image: Deep Blue and
Grand Canyon II vessels support
the Thunder Horse South
expansion project in the US Gulf
of Mexico.

More information

Upstream regional analysis
Page 244

BP Annual Report and Form 20-F 2016We see our scale and long history in many of the great basins in the
world as a differentiator for BP and believe in the strength of our
incumbent positions. We are resilient and balanced – in terms of
geography, hydrocarbon type and geology – and rather than being
restricted by a traditional way of working, we have and will continue to
use creative business models to generate value. We are also investing
to modernize and transform the Upstream – embracing innovation,
digitization and the adoption of big data, which we believe can drive a
real step change in performance and efficiency.

Financial performance

Sales and other operating

revenuesa

RC profit (loss) before interest

and tax

Net (favourable) unfavourable

impact of non-operating items
and fair value accounting
effects

Underlying RC profit (loss) before

interest and tax

Organic capital expenditure
Additions to non-current assets
BP average realizationsc
Crude oild e
Natural gas liquids
Liquids d

Natural gas
US natural gas

Total hydrocarbons d
Average oil marker pricesf
Brent
West Texas Intermediate
Average natural gas

marker prices

Average Henry Hub gas priceg

Average UK National Balancing

2016

2015

$ million
2014

33,188

43,235

65,424

574

(937)

8,934

(1,116)

2,130

6,267

(542)
16,048b
17,879

1,193
16,307
17,635

15,201
18,994
22,587

49.72
20.75
47.32

$ per barrel
94.74
36.15
88.88
$ per thousand cubic feet
5.70
3.80
$ per barrel of oil equivalent
61.17

3.80
2.10

35.46

39.99
17.31
38.27

2.84
1.90

28.24

43.73
43.34

2.46

$ per million British thermal units
4.43
pence per therm

2.67

Point gas price f

34.63

42.61

50.01

a Includes sales to other segments.
b 2016 includes the consideration for the Abu Dhabi ADCO onshore oil concession renewal.
c Realizations are based on sales by consolidated subsidiaries only, which excludes
equity-accounted entities.
d Production volume recognition methodology for our Technical Service Contract arrangement
in Iraq has been simplified to exclude the impact of oil price movements on lifting
imbalances. A minor adjustment has been made to comparative periods. There is no impact
on the financial results.
e Includes condensate and bitumen.
f All traded days average.
g 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 that are derived using
differentials or a lagged impact from the Brent crude oil price.

Brent ($/bbl)

150

120

2016

2015

2014

Five-year range

Jan

Feb Mar

Apr May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

The dated Brent price in 2016 averaged $43.73 per barrel. Prices
were lowest early in the year, averaging just $34 in the first quarter;
rebounding to an average of about $46 in both the second and third
quarters, and rising again in the fourth quarter to $49 as OPEC and
non-OPEC members discussed – and ultimately agreed – co-ordinated
production cuts.

Henry Hub ($/mmBtu)

The 2016 Henry Hub First of Month Index price was slightly lower than
2015 ($2.67).

The average UK National Balancing Point gas price in 2016 fell by 19%
compared with 2015 (2015 a decrease of 15% on 2014). This reflected
ample supplies in Europe with record Russian flows offsetting declining
indigenous production. For more information on the global energy
market in 2016, see page 20.

Financial results
Sales and other operating revenues for 2016 decreased compared with
2015, primarily reflecting lower liquids and gas realizations, and lower
gas marketing and trading revenues. The decrease in 2015 compared
with 2014 primarily reflected significantly lower liquids and gas
realizations and lower gas marketing and trading revenues partly offset
by higher production.

Replacement cost loss before interest and tax for the segment included
a net non-operating gain of $1,753 million. This primarily relates to the
reversal of impairment charges associated with a number of assets,
following a reduction in the discount rate applied and changes to future
price assumptions. See Financial statements – Note 4 for further
information. Fair value accounting effects had an unfavourable impact of
$637 million relative to management’s view of performance.

52.39
48.71

$ per barrel

98.95
93.28

2016

2015

2014

Five-year range

Jan

Feb Mar

Apr May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performance

The 2015 result included a net non-operating charge of $2,235 million,
primarily related to a net impairment charge associated with a number of
assets, following a further fall in oil and gas prices and changes to other
assumptions. Fair value accounting effects had a favourable impact of
$105 million relative to management’s view of performance. The 2014
result included a net non-operating charge of $6,298 million, primarily
related to impairments associated with several assets, mainly in the
North Sea and Angola reflecting the impact of the lower near-term
price environment, revisions to reserves and increases in expected
decommissioning cost estimates. Fair value accounting effects had
a favourable impact of $31 million relative to management’s view of
performance.

After adjusting for non-operating items and fair value accounting effects,
the underlying RC result before interest and tax was a loss, compared
with a profit in 2015. This lower result primarily reflected lower liquids
and gas realizations, as well as adverse foreign exchange impacts
and lower gas marketing and trading results. This was partly offset
by lower costs including the benefits of simplification and efficiency
activities, lower exploration write-offs, lower depreciation, depletion and
amortization expense and lower rig cancellation charges.

Compared with 2014 the 2015 result reflected significantly lower
liquids and gas realizations, as well as rig cancellation charges and
lower gas marketing and trading results, partly offset by lower costs
including benefits from simplification and efficiency activities and lower
exploration write-offs, and higher production.

Additions to non-current assets were $17.9 billion and organic capital
expenditure on an accruals basis was $16.0 billion. Excluding the
Abu Dhabi onshore oil concession renewal for which shares were
used as consideration, organic capital expenditure was $13.6 billion,
significantly lower than the $16.3 billion in 2015.

In total, disposal transactions generated $0.8 billion in proceeds in 2016,
with a corresponding reduction in net proved reserves of 241mmboe
within our subsidiaries.

The major disposal transaction during 2016 was the transfer of our
Norway assets to Aker BP. More information on disposals is provided
in Upstream analysis by region on page 244 and Financial statements –
Note 4.

Outlook for 2017
• We expect to start up seven new major projects in 2017.

• We expect underlying production to be higher than 2016. The actual
reported outcome will depend on the exact timing of project start-ups,
divestments, OPEC quotas and entitlement impacts in our production-
sharing agreements .

• Capital investment is expected to decrease, largely reflecting our
commitment to continued capital discipline and the rephasing and
refocusing of our activities and major projects where appropriate in
response to the current business environment.

• We expect oil prices will continue to be challenging in the near term

(see page 20).

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

and other contractual agreements. We

Our exploration and new access teams work to enable us to optimize
our resource base and provide us with a greater number of options.
In the current environment, we are spending less on exploration and
we will spend a material part of our exploration budget on lower-risk,
shorter-cycle-time opportunities around our incumbent positions.

50+

years in
the Norwegian
North Sea

An innovative business
model

BP joined forces with Det norske and Aker in 2016 to form Aker
BP ASA. Listed on the Oslo stock exchange, Aker BP is now
Norway’s largest independent oil and gas producer.

The company’s strategy is underpinned by a blend of Det norske’s
nimble business practices, Aker’s industrial experience and BP’s
global scale expertise across the hydrocarbon value chain. By
combining the assets of these companies, Aker BP has a strong
balance sheet with the financial resources to support both ongoing
investment in the business and distributions to shareholders.

BP expects to apply the knowledge gained from Aker BP across its
own businesses.

New access in 2016
We gained access to new acreage covering almost 71,000km2 in 10
countries – Australia, Canada, China, Egypt, Ireland, Mauritania, Norway,
Russia, the UK and the US.

Exploration success
We participated in eight potentially commercial discoveries in 2016 –
Baltim SW-1, Baltim SW-2, Nooros East and Nooros West in Egypt,
Gibson and Nozomi in the Gulf of Mexico, and Golfinho and Zalophus in
Angola.

Exploration and appraisal costs
Excluding lease acquisitions, the costs for exploration and appraisal
were $1,402 million (2015 $1,794 million, 2014 $2,911 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 20% of exploration and appraisal costs were directed
towards appraisal activity. We participated in 40 gross (21.68 net)
exploration and appraisal wells in seven countries.

Exploration expense
Total exploration expense of $1,721 million (2015 $2,353 million,
2014 $3,632 million) included the write-off of expenses related to
unsuccessful drilling activities, lease expiration or uncertainties around
development in the Gulf of Mexico ($611 million), Brazil ($601 million),
and others ($167 million), partially offset by a net write-back of
$103 million across several blocks in India (see Financial statements –
Note 7).

Reserves booking
Reserves bookings 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 2016,
decreased by less than 1% (a decrease of 1% for subsidiaries and an
increase of 9% for equity-accounted entities) compared with reserves at
31 December 2015.

BP Annual Report and Form 20-F 2016Proved reserves replacement ratio
The proved reserves replacement ratio for the segment in 2016,
including the impact of the Abu Dhabi onshore oil concession renewal,
was 96% for subsidiaries and equity-accounted entities (2015 33%),
101% for subsidiaries alone (2015 28%) and 61% for equity-accounted
entities alone (2015 76%). For more information on proved reserves
replacement for the group see page 251.

Invested around

$30bn

in Egypt

Upstream proved reservesa (mmboe)

Liquids

1. Subsidiaries
2. Equity-accounted entities

Total

Gas

3. Subsidiaries
4. Equity-accounted entities

Total

4,151
787
4,938

4,981
445
5,425

Estimated net proved reservesa (net of royalties)

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

2016

2015

2014

million barrels

3,778
771
4,549

373
16
389

4,151
787
4,938

28,888
2,580
31,468

9,131
1,232
10,363

3,560
694
4,254

422
13
435

3,982
707
4,689

3,582
702
4,283

510
16
526

4,092
717
4,809

billion cubic feet
32,496
2,373
34,869

30,563
2,465
33,027

million barrels of oil equivalent

9,252
1,132
10,384

9,694
1,126
10,821

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 2016
upstream operations in Argentina, Bolivia, Russia and Norway as well as some of our
operations in Angola, Abu Dhabi and Indonesia, were conducted through equity-accounted
entities.
d Includes 16 million barrels (19 million barrels at 31 December 2015 and 21 million barrels at
31 December 2014) in respect of the 30% non-controlling interest in BP Trinidad & Tobago
LLC.
e Includes 2,026 billion cubic feet of natural gas (2,359 billion cubic feet at 31 December 2015
and 2,519 billion cubic feet at 31 December 2014) in respect of the 30% non-controlling interest
in BP Trinidad & Tobago LLC.

Increasing gas in Egypt

BP has a long track record in Egypt stretching back over 50 years with
investments exceeding $30 billion – making us one of the largest
foreign investors in the country.

In addition to our strong incumbent position and progress with the
West Nile Delta major project, BP purchased a 10% interest in the
Zohr gas field from Eni and has plans to accelerate the development
of three significant gas discoveries in the East Nile Delta area. The
first of these – Atoll in the North Damietta offshore concession – has
been approved for an early production scheme to bring up to 300
million standard cubic feet a day (mmscf/d) of gas to the Egyptian
domestic gas market starting in the first half of 2018.

And in our Nooros development, we ramped up production from
zero in the first half of 2015 to 875mmscf/d gross in January 2017.

We also made an important discovery in the area’s Baltim South
development in 2016, which we are appraising to determine the full
resource potential. If viable, we plan to utilize existing infrastructure
to accelerate its development and achieve early production start-up.

These achievements demonstrate our commitment to playing an
ongoing role in helping to secure Egypt’s energy supply for many
years to come.

Developments
start-ups in 2016: two in Algeria, one in
We achieved six major project
Alaska, one in Angola and two in the Gulf of Mexico. In addition to these,
we made good progress in projects in AGT (Azerbaijan, Georgia, Turkey),
the Gulf of Mexico, Oman and Egypt.

• Azerbaijan, Georgia, Turkey – the Shah Deniz 2 project continues

to move ahead with the award of contract for the transport and
installation of the deep water subsea production systems. We also
signed a letter of intent for the future development of the Azeri-Chirag-
Gunashli field, covering the development of the field to the end of
2049.

• Gulf of Mexico – we sanctioned the re-evaluated Mad Dog Phase 2
project, having reduced overall project cost by approximately 60%
compared to initial design.

• Oman – development of the Khazzan project continued, with the

project being more than 92% complete as at the year-end. We also
signed an agreement to extend the licence area, allowing for a second
phase of development in the future.

• Egypt – we sanctioned the development of the Atoll Phase 1 project

and signed concession amendments in three other projects that allow
for the economic development of the Nooros field.

Subsidiaries’ development expenditure incurred, excluding midstream
activities, was $11.1 billion (2015 $13.5 billion, 2014 $15.1 billion).

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performance
Our project pipeline

*BP operated

Project

2016 start-ups
Angola LNG (restart)
In Amenas compression
In Salah Southern Fields
Point Thomson
Thunder Horse water injection*
Thunder Horse South expansion*

Location

Angola
Algeria
Algeria
US Alaska
US Gulf of Mexico
US Gulf of Mexico

Egypt
UK North Sea
Trinidad
Oman
Australia
Azerbaijan
Indonesia
Trinidad

Expected start-ups 2017-2021
Projects currently under constructiona
Atoll Phase 1*
Culzean
Juniper*
Oman Khazzan Phase 1*
Persephone
Shah Deniz Stage 2*
Tangguh expansion*
Trinidad onshore compression*
West Nile Delta Giza/Fayoum/Raven* Egypt
Egypt
West Nile Delta Taurus/Libra*
Australia
Western Flank Phase B
Egypt
Zohr
UK North Sea
Clair Ridge*
US Gulf of Mexico
Constellation
UK North Sea
Quad 204*
US Gulf of Mexico
Mad Dog Phase 2*

Expected start-ups 2017-2021
Design and appraisal phase
Angelin*

Trinidad offshore compression*

KG-D6 D55

KG-D6 R-Series

Oman Khazzan Phase 2*

Vorlich*

Trinidad

India

Oman

UK North Sea

West Nile Delta 2 Follow On*

Egypt

Alligin*

Atlantis Phase 3*

UK North Sea

US Gulf of Mexico

Gas
Oil

Type

Production
Our offshore and onshore oil and natural gas production assets 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. These include production from conventional and
unconventional (coalbed methane and shale) assets. Our principal areas
of production are Angola, Argentina, Australia, Azerbaijan, Egypt, Iraq,
Trinidad, the UAE, the UK and the US.

With BP-operated plant reliability increasing from around 86% in 2011
to 95% in 2016, efficient delivery of turnarounds and strong infill drilling
performance, we have flattened base decline to less than 3% on
average over the last four years. Our long-term expectation for managed
base decline remains at the 3-5% per annum guidance we have
previously given.

Production (net of royalties)a

Liquids
Crude oilb
Subsidiariesc
Equity-accounted entitiesd

Natural gas liquids
Subsidiaries
Equity-accounted entitiesd

Total liquids
Subsidiariesc
Equity-accounted entitiesd

Natural gas
Subsidiaries
Equity-accounted entitiesd

Total hydrocarbons
Subsidiariesc
Equity-accounted entitiesd

2016

2015

2014

thousand barrels per day

943
179
1,122

82
4
86

1,025
184
1,208

5,302
494
5,796

933
165
1,099

88
7
95

1,022
172
1,194

834
163
997

91
7
99

926
170
1,096

million cubic feet per day
5,585
431
6,016

5,495
456
5,951

thousand barrels of oil equivalent per day

1,939
269
2,208

1,969
251
2,220

1,889
245
2,133

a Because of rounding, some totals may not agree exactly with the sum of their component
parts..
b Includes condensate and bitumen.
c Production volume recognition methodology for our Technical Service Contract arrangement
in Iraq has been simplified to exclude the impact of oil price movements on lifting
imbalances. A minor adjustment has been made to comparative periods. There is no impact
on the financial results.
d Includes BP’s share of production of equity-accounted entities in the Upstream segment..

Beyond 2021
We have a deep hopper of projects that are currently under
appraisal. Our focus here is to ensure we maximize the business
opportunity and select the optimum project concept before we
move it forward into design. We do not expect to progress all of the
projects – only the best. This includes:

• a mix of resource types: split across conventional oil,
deepwater oil, conventional gas and unconventionals

• geographic spread: from Alaska to Australia and Argentina to

Russia

• a range of development types: from exploration to brownfield

and near-field.

a For further information on the development of the Taas-Yuryakh oil field (also expected to
start up in the period 2017-2021) see page 248.

BP Annual Report and Form 20-F 2016
Our total hydrocarbon production for the segment in 2016 was 0.5%
lower compared with 2015. The decrease comprised a 1.5% decrease
(0.3% increase for liquids and 3.5% decrease for gas) for subsidiaries
and a 7.2% increase (6.7% increase for liquids and 8.3% increase
for gas) for equity-accounted entities compared with 2015. For more
information on production see Oil and gas disclosures for the group on
page 251.

In aggregate, underlying production was flat versus 2015.

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
Our integrated supply and trading function markets and trades our
own and third-party natural gas (including LNG), power and NGLs.
This provides us with routes into liquid markets for the gas we produce
and generates margins and fees from selling physical products
and derivatives to third parties, together with income from asset
optimization and trading. This means we have a single interface with gas
trading markets and one consistent set of trading compliance and risk
management processes, systems and controls.

The activity primarily takes place in North America, Europe and Asia, and
supports group LNG activities, managing market price risk and creating
incremental trading opportunities through the use of commodity
derivative contracts. It also enhances margins and generates fee
income from sources such as the management of price risk on behalf of
third-party customers.

Our trading financial risk governance framework is described in Financial
statements – Note 28 and the range of contracts used is described in
Glossary – commodity trading contracts on page 280.

Production
capacity up by

50%

Tangguh

Expanding our Tangguh
gas facility

By using an LNG train to convert natural gas into liquid form we make
it more practical and commercially viable to transport by sea across
countries.

At our Tangguh LNG facility in Indonesia, we’ve supplied natural gas
to two 3.8 million tonnes per annum (mtpa) LNG trains since 2009.

And in line with our shifting focus to gas in BP, we are adding a third
train that will bring total plant capacity to 11.4mtpa. We received
approval for this expansion project with our production-sharing
agreement partners in 2016. The project will also include construction
of two offshore platforms and 13 new production wells, as well as
an expanded LNG loading facility and supporting infrastructure. We
expect train 3 to come into operation in 2020.

Through this project we are supporting the country’s growing
demand for energy. Around 75% of the LNG production from train 3
will be sold to the Indonesian state electricity company. The project
will also help with economic growth in the area and is expected to
provide 10,000 jobs over the project period.

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performanceDownstream

We are building a safer business and growing our
earnings potential with more still to come.

Tufan Erginbilgic Chief executive, Downstream

In summary

95.3% 1.7

refining availability
(2015 94.7%)

million barrels of oil refined
per day
(2015 1.7mmb/d)

43%

14.2

of lubricants sales were
premium grade
(2015 42%)

million tonnes of
petrochemicals produced
(2015 14.8mmte)

Downstream proﬁtability ($ billion)

2016

2015

2014

2013

2012

5.2

5.6

7.1

7.5

3.7

4.4

2.9

3.6

6.5

Replacement cost (RC) proﬁt before interest and tax
Underlying RC proﬁt before interest and tax

Our business model and strategy
The Downstream segment has global manufacturing and
marketing operations. It is the product and service-led
arm of BP, made up of three businesses:

Our strategic priorities are:

• Safe and reliable operations – this remains our first
priority and we continue to drive improvement in
personal and process safety performance.

• Fuels – includes refineries, logistic networks, fuels

• Advantaged manufacturing – we continue to build a

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

• Lubricants – manufactures and markets lubricants and
related products and services globally, adding value
through brand, technology and relationships, such as
collaboration with original equipment manufacturing
partners.

• Petrochemicals – manufactures, sells and distributes
products, that are produced mainly using proprietary
BP technology, and are then used by others to make
essential consumer products such as paint, plastic
bottles and textiles. We also license our technologies
to third parties.

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 that meet our customers’ needs.

Our strategy focuses on a quality portfolio that aims
to lead the industry, as measured by net income per
barrel
cash flow .

, with improving returns and growing operating

, by having a competitively

top-quartile refining business as measured through net
cash margin per barrel
advantaged portfolio underpinned by operational
excellence that helps to reduce exposure to margin
volatility. In petrochemicals we seek to sustainably
improve earnings potential and make the business
more resilient to a bottom-of-cycle environment
through portfolio repositioning, improved operational
performance and efficiency benefits.

• Fuels and lubricants marketing – we invest in

higher-returning businesses with reliable cash
flows and growth potential.

• Simplification and efficiency – this remains central to

what we do to support performance improvement and
make our businesses even more competitive.

• Transition to a lower carbon and digitally enabled future

– we are pursuing and developing new offers and
products that support the transition to a lower carbon
and digitally enabled future over the long term.

Disciplined execution of our strategy is helping improve
our underlying performance, capture opportunities for
further growth, generate attractive returns and create a
more resilient business that is better able to withstand a
range of market conditions; and create opportunities for
future growth. We aim to ensure Downstream remains a
reliable source of cash flow growth for BP.

Main image: Vaporizer towers
convert liquid nitrogen to gas
at our US Whiting refinery.

More information

Downstream plant capacity
Page 249

BP Annual Report and Form 20-F 2016Financial performance

Sale of crude oil through spot

and term contracts

Marketing, spot and term sales

2016

2015

$ million
2014

31,569

38,386

80,003

of refined products

126,419

148,925

227,082

Other sales and operating

revenues

Sales and other operating

revenuesa

RC profit (loss) 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 (loss) before

interest and taxb

Fuels
Lubricants
Petrochemicals

Organic capital expenditure
Additions to non-current assets

9,695

13,258

16,401

167,683

200,569

323,486

3,337
1,439
386
5,162

390
84
(2)
472

3,727
1,523
384
5,634
2,141
3,109

5,858
1,241
12
7,111

137
143
154
434

5,995
1,384
166
7,545
2,101
2,130

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

389
(136)
450
703

3,219
1,271
(49)

4,441
2,995
3,121

a Includes sales to other segments.
b Income from petrochemicals produced at our Gelsenkirchen and Mülheim sites in Germany
is reported in the fuels business. Segment-level overhead expenses are included in the fuels
business result.

Financial results
Sales and other operating revenues in 2016 and 2015 were lower due to
lower crude and product prices.

Replacement cost profit before interest and tax for the year ended
31 December 2016 included a net non-operating charge of $24 million,
mainly relating to a gain on disposal in our fuels business which was
more than offset by restructuring and other charges. The 2015 result
included a net non-operating charge of $590 million, mainly relating to
restructuring charges, while the 2014 result included a net non-operating
charge of $1,570 million, primarily relating to impairment charges in our
petrochemicals and fuels businesses. In addition, fair value accounting
effects had an unfavourable impact of $448 million, compared with a
favourable impact of $156 million in 2015 and $867 million in 2014.

After adjusting for non-operating items and fair value accounting effects,
underlying RC profit before interest and tax in 2016 was $5,634 million.

Additions to non-current assets in 2016 included the asset exchange
relating to the dissolution of our German refining joint operation with
Rosneft as well as organic capital expenditure.

Outlook for 2017
• We anticipate a gradual improvement in the refining environment,

although refining margins for the year are expected to remain at the
lower end of the recent historical range.

• We expect the financial impact of routine refinery turnarounds to be
slightly higher than 2016 as a result of increased turnaround activity,
particularly in Europe.

Our fuels business
The fuels strategy focuses primarily on fuels value chains (FVCs). This
includes building a top-quartile net cash margin refining business through
operating reliability, feedstock and location advantage and efficiency
improvements to our already competitively advantaged portfolio.

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

Underlying RC profit before interest and tax was lower compared with
2015 reflecting a significantly weaker refining environment and the
impact from a particularly large turnaround at Whiting refinery, partially
offset by lower costs reflecting the benefits from our simplification and
efficiency programmes, an increased fuels marketing performance
driven by retail growth and higher refining margin capture in our
operations. Compared with 2014, the 2015 result was higher reflecting
a strong refining environment, improved refining margin optimization
and operations, and lower costs from simplification and efficiency
programmes.

reﬁning availability

Operational excellence
at Kwinana

We get the best value from our refineries when they run efficiently
at full capacity. Across all of our refineries staff work hard to maintain
safe and reliable operations, prevent unplanned shutdowns and
optimize operational performance.

Kwinana, just outside Perth in Western Australia, is the country’s
largest refinery. It supplies virtually all the petrol and diesel demand
in the country‘s south west and all jet fuel for Perth Airport. And for
the last three years we’ve been implementing improvement works
across the refinery – covering everything from sourcing good quality
crude to effective planning and scheduling, and maintaining effective
manufacturing operations.

We are already seeing a difference at Kwinana, with the refinery
improving its availability – the percentage of time process units
are capable of running at full capacity – in 2016. And the refinery’s
utilization – the difference between production capacity and what’s
actually processed – places it in the top quartile of Asia-Pacific
refineries based on the latest fuels study by Solomon Associates.

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performance

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
Australia
BP RMM

Azeri Light
Brent

BP reﬁning marker margin ($/bbl)

2016

2015

$ per barrel
2014

16.9

13.2
10.0
9.0
10.9
11.8

24.0

19.0
14.5
12.7
15.4
17.0

16.6

17.4
12.5
10.6
13.5
14.4

2016

2015

2014

Five-year range

Jan

Feb Mar

Apr May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

The average global RMM in 2016 was $11.8/bbl, $5.2/bbl lower than in
2015, and the lowest since 2010. The decrease was driven by product
oversupply resulting from higher refinery utilization which outstripped
growth in demand.

Reﬁning
At 31 December 2016 we owned or had a share in 11 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 249.

In 2016 refinery operations were strong, with refining availability
sustained at around 95.3% and utilization rates of 91% for the year.
Overall refinery throughputs in 2016 were flat compared with 2015
with increased throughputs in our refining portfolio offset by the impact
from ceasing operations at Bulwer in 2015 and the large turnaround at
Whiting.

In December 2016 the previously announced dissolution of our German
refining joint operation with Rosneft was completed. This will simplify
and refocus our refining business in the heart of Europe.

Refinery throughputsa
US
Europe
Rest of worldb
Total

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

2016

646
803
236
1,685

95.3

2,825
2,775
5,600
2,169
7,769

2015

657
794
254
1,705

2014
thousand barrels per day
642
782
297
1,721
%
94.9

94.7

thousand barrels per day
2,872
2,835
2,448
2,770
5,320
5,605
2,360
2,098
7,680
7,703

a Refinery throughputs reflect crude oil and other feedstock volumes.
b Bulwer refinery in Australia ceased refining operations in 2015.
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. 71,000 barrels
per day relate to revenues reported by the Upstream segment.

Marketing and logistics
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 excellence in operational and
transactional processes and deliver compelling customer offers in the
various markets where we operate. In 2016 we completed the sale of
our Amsterdam oil terminal and announced our intention to divest some
of our fuels terminals in the UK. This reflects our continued focus on
increasing our competitiveness through having an advantaged portfolio.
We supply fuel and related retail services to consumers through
company-owned and franchised retail sites, as well as other channels,
including dealers 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
2,900
18,000

2016
7,100
8,100
2,800
18,000

2015
7,000
8,100
2,900
18,000

f Reported to the nearest 100. 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 and includes our interest in equity-accounted entities.

Retail is the most material element of our fuels marketing operations and
has good exposure to growth markets. In addition we have distinctive
partnerships with leading retailers and plan to expand our networks
further. Retail is a significant source of growth today and is expected
to be so in the future. This year we continued the rollout of our new
BP fuels with ACTIVE technology which are now sold in 13 countries
globally (see page 34). We also entered into two new convenience
partnerships in Europe with leading food retailing companies, REWE to
go® in Germany and Albert Heijn to go® in the Netherlands.

In December 2016 we announced that we will be establishing a strategic
partnership with Woolworths in Australia. The agreement includes us
acquiring Woolworths’ fuel and convenience sites for a total consideration
of $1.3 billion and entering into a strategic convenience partnership with
them. The transaction is subject to regulatory approvals.

BP Annual Report and Form 20-F 2016

Aviation
Air BP is one of the world’s largest global aviation fuels suppliers. Our
strategic aim is to maintain a strong presence in our core locations of
Europe and the US, while expanding our portfolio in airports that offer
long-term competitive advantage in material growth markets such as
Asia and South America. Air BP serves many major commercial airlines
as well as the general aviation sector. We have marketing sales of
more than 430,000 barrels per day, and in 2016 entered into two joint
venture partnerships to market aviation fuels in Peru and Indonesia.
We also announced a strategic partnership with Fulcrum BioEnergy®
and partnered with RocketRoute® to launch a digital app that provides
online fuel purchasing and payment functionality across our global
network of aviation fuel locations.

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 60% 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 that we believe provides
us with significant competitive advantage.

In technology, we apply our expertise to create differentiated, premium
lubricants and high-performance fluids for customers in on-road, off-
road, sea and industrial applications globally. This year we launched
Castrol MAGNATEC with DUALOCK technology, our latest premium
brand lubricant, which reduces warm-up and stop-start wear by up to
50% (see page 12).

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:

• Applying cutting-edge technologies in the development and

formulation of advanced products.

• Creating and developing product brands and clearly communicating

their benefits to customers.

• 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 that was higher compared with 2015 – which in turn was
higher than 2014. In fact this 2016 result was a record performance for
lubricants. Both the 2016 and 2015 results reflected continued strong
performance in growth markets and premium brands as well as lower
costs achieved through simplification and efficiency programmes.

In 2016 we sold approximately 20% from our shareholding in Castrol
India Limited, reducing our shareholding to 51%. We continue to be the
majority shareholder and have strategic control of the company.

Supply and trading
Our integrated supply and trading function is responsible for delivering
value across the overall crude and oil products supply chain. This
structure enables our downstream businesses to maintain a single
interface with oil trading markets and operate with one set of trading
compliance and risk management processes, systems and controls. It
has a two-fold purpose:

First, it seeks to identify the best markets and prices for our crude oil,
source optimal raw materials for our refineries and provide competitive
supply for our marketing businesses. We will often sell our own crude
and purchase alternative crudes from third parties for our refineries
where this will provide incremental margin.

Second, it 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 combination with rights to access storage and transportation capacity,
this allows it to access advantageous price differences between
locations and time periods, and to arbitrage between markets.

The function has trading offices in Europe, North America 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.

Our trading financial risk governance framework is described in Financial
statements – Note 28 and the range of contracts used is described in
Glossary – commodity trading contracts on page 280.

Low carbon energy
solutions

10-year

commitment to
reduce emissions

BP supplies fuel for more than 6,000 flights a day and we work to
help our aviation customers reduce their emissions in a number of
ways. At Oslo airport in Norway we helped to make biojet available
through its normal supply infrastructure. As a result of Air BP’s
collaboration, the airport won the 2016 Eco-Innovation environment
award from Airport Carbon Accreditation.

We also invested in Fulcrum BioEnergy® – a company that produces
sustainable jet fuel from household waste. Our strategic partnership
aims to help the company bring biojet to the market at scale.

But our commitment doesn’t end there – in 2016 we achieved
carbon neutrality for our into-plane fuelling services across a network
of more than 200 Air BP-operated facilities. And we have made a 10-
year commitment to retain our carbon neutral accreditation
and aim to reduce emissions by 5% over this period.

All of these changes contribute to the International Air Transport
Association’s aim to achieve carbon neutral growth by 2020 and a
50% reduction in carbon emissions by 2050.

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performanceIn 2016 the petrochemicals business delivered a higher underlying RC
profit before interest and tax compared with 2015 – which in turn was
higher than 2014. The result reflected strong operations and margin
capture supported by the continued rollout of our latest advanced
technology, as well as benefits from a slightly improved environment
particularly in olefins and derivatives. Compared with 2014, the 2015
result reflected improved operational performance and benefited from
our simplification and efficiency programmes leading to lower costs.
Our petrochemicals production of 14.2 million tonnes in 2016 was lower
than 2015 but higher than 2014 (2015 14.8mmte, 2014 14.0mmte),
due to the divestment of the Decatur petrochemicals complex in 2016
and the low margin environment in 2014 compared with 2015 driving
reduced output.

As part of our strategy to refocus our global petrochemicals business for
long-term growth, we completed the sale of the Decatur petrochemicals
complex in Alabama, US in March 2016.

We completed the upgrade of our PTA plant in Geel, Belgium, using
our latest proprietary technology and are continuing the upgrade at
Cooper River in South Carolina, US, which is scheduled to complete
in early 2017. We expect these investments to significantly increase
manufacturing efficiency at both facilities.

We are also leveraging our proprietary technology to offer a low carbon
PTA solution to manufacturers, brand owners and their customers. In
2016 we launched PTAir, which supports a carbon footprint of around
30% lower than the average European PTA production.

Our licensing business continues to be a core part of our growth
strategy and in December 2016 Reliance Industries Limited successfully
commissioned the first phase of its paraxylene plant in Gujarat, India
using BP’s proprietary technology. The plant, with a capacity of 1.8
million tonnes, is the world’s largest paraxylene unit and is built with
BP’s leading crystallization technology which delivers greater energy
efficiency.

Available in

13 countries

Innovative fuels

Engine technologies continually evolve. So we work to anticipate
and understand these changes to make sure we develop fuels that
complement the latest engine innovations – while continuing to
benefit older engines too.

We have rolled out our new BP fuels with ACTIVE technology in
13 countries including Australia, South Africa and the US. These
fuels use an innovative formula designed to actively fight dirt in the
car’s engine and protect against it building up. This helps keep
engines running as intended by car manufacturers – smoothly and
efficiently – and helps reduce the risk of unplanned maintenance.

Our petrochemicals business
Our petrochemicals strategy is to improve our earnings potential and
make the business more resilient to a bottom-of-cycle environment.
We develop proprietary technology to deliver leading cost positions
compared with our competition. We manufacture and market four main
product lines:

• Purified terephthalic acid (PTA).

• Paraxylene (PX).

• Acetic acid.

• Olefins and derivatives.

We also produce a number of other specialty petrochemicals products.

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 in their domestic market.

We are two years into our strategic programme to significantly improve
the resilience of the business to a bottom-of-cycle environment through:

• Repositioning a significant portion of our portfolio including shutting

down older capacity in the US and Asia.

• Retrofitting our best technology at our advantaged sites to reduce

overall operating costs.

• Growing third-party licensing income to create additional value.

• Delivering operational improvements focused on turnaround efficiency

and improved reliability.

• Delivering additional value through simplification and efficiency

programmes.

BP Annual Report and Form 20-F 2016Rosneft

Rosneft is the largest oil company in
Russia, with a strong portfolio of current
and future opportunities.

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BP and Rosneft
• BP’s 19.75% shareholding in Rosneft allows us to benefit from a

diversified set of existing and potential projects in the Russian oil and
gas sector.

• Russia has one of the largest and lowest cost hydrocarbon resource

bases in the world and its resources play an important role in long-term
energy supply to the global economy.

• BP’s strategy in Russia is to support Rosneft’s overall performance

and growth through collaboration on technology and best practice, and
to build a material business based on standalone projects with Rosneft
in Russia and internationally. BP remains committed to our strategic
investment in Rosneft, while complying with all relevant sanctions.

2016 summary
• Rosneft continued optimizing its portfolio and increased total

hydrocarbon production by 4%.

• Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz),

which is wholly owned by the Russian government. In December an
agreement was signed to sell 19.5% from Rosneftegaz’s 69.5%
shareholding in Rosneft to a consortium of international investors,
comprising Qatar Investment Authority and Glencore. Following
completion of the transaction, at the year-end Rosneftegaz’s
shareholding in Rosneft was 50% plus one share.

• Rosneft acquired a 50.0755% stake in Russian oil company Bashneft
in October and subsequently increased its shareholding to 60.33% as
a result of an offer to buy out minority shareholders. This acquisition is
expected to provide Rosneft with significant synergies and additional
refining throughput and liquid hydrocarbon production. BP accounts for
its share of production and reserves resulting from the acquisition
through its 19.75% stake in Rosneft.

About Rosneft
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 Russia’s key hydrocarbon regions.
Rosneft’s hydrocarbon production reached a record of 5.4mmboe/d in
2016. Gas production for the year increased by 7.3% to 67.1bcma or
6.47bcf/d compared with 2015.

Rosneft is also the leading Russian refining company based on
throughput. It owns and operates 13 refineries in Russia, including three
recently acquired in the Bashneft transaction. Rosneft also owns and
operates more than 2,950 retail service stations in Russia and abroad.
These include BP-branded sites operating under a licensing agreement
acquired as part of the TNK-BP acquisition in 2013, and Bashneft-
branded stations. Downstream operations include jet fuel, bunkering,
bitumen and lubricants. Rosneft refinery throughput in 2016 reached a
record level of 2.028mmb/d versus 1.966mmb/d in 2015.

BP‘s strategy in Russia
Our strategy is to work in co-operation with Rosneft to increase total
shareholder return and partner with it in building a material business
outside of the shareholding. This strategy is implemented through our
activities in four areas:

• Rosneft Board of Directors: BP has two nominees on the Rosneft

Board of Directors and its committees.

• Technology: develop and apply technology to improve oil and gas field

and refining performance in collaboration with Rosneft.

• Joint ventures: partner with Rosneft to generate incremental value
from joint ventures that are separate from BP’s core shareholding.

• Rosneft also agreed to purchase a 49% stake in Essar Oil Limited,

which owns the Vadinar refinery in India, one of the largest and most
advanced refineries in the world.

• Technical services: the partners collaborate on the provision of

technical services on a contractual basis to improve asset
performance.

• In July BP received $332 million, net of withholding taxes (2015 $271

million, 2014 $693 million), representing its share of Rosneft’s dividend
of 11.75 Russian roubles per share. This dividend stood at 35% of
Rosneft’s 2015 IFRS net profit, an increase from the 25% paid in the
previous year.

• Two BP nominees, Bob Dudley and Guillermo Quintero, serve on

Rosneft’s nine member Board of Directors. Bob Dudley is a member
of its Strategic Planning Committee and Guillermo Quintero is a
member of its HR and Remuneration Committee.

The following developments and activities in 2016 have served to
support and progress this strategy:

• BP holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas), a

joint venture with Rosneft that is developing the Srednebotuobinskoye
oil and gas condensate field in East Siberia. In October Rosneft sold a
29.9% interest in the joint venture to a consortium consisting of Oil
India Limited, Indian Oil Corporation Limited and Bharat
PetroResources Limited. BP’s interest in Taas is reported through the
Upstream segment.

• US and EU sanctions remain in place on certain Russian activities,

• Rosneft and BP completed a transaction in October to create a new

individuals and entities, including Rosneft.

joint venture, Yermak Neftegaz LLC (Yermak). It will conduct onshore
exploration in the West Siberian and Yenisei-Khatanga basins. Yermak
is 51% owned by Rosneft and 49% by BP, and currently holds seven
exploration and production licences. The venture will also carry out
further appraisal work on the Baikalovskoye field, an existing Rosneft

See Glossary.

BP Annual Report and Form 20-F 2016

discovery in the Yenisei-Khatanga area of mutual interest. BP’s interest
in Yermak is reported through the Upstream segment.

• Rosneft, BP and Schlumberger signed agreements in September for

collaboration on seismic research and the development of an
innovative cableless onshore seismic acquisition technology. The
technology aims to revolutionize the design and acquisition of seismic
surveys and increase the efficiency of exploration, appraisal and field
development (see page 12).

• BP and Rosneft completed the dissolution of their German refining

joint operation Ruhr Oel GmbH (ROG) in December.

During the year Rosneft continued actively managing its portfolio.
Highlights included:

• Selling a 49.9% share in its subsidiary Vankorneft (excluding

infrastructure) to ONGC Videsh Limited and a consortium of Indian
companies comprising Oil India Limited, Indian Oil Corporation Limited
and Bharat PetroResources Limited. The base price was $4.2 billion.

• Signing an agreement to sell a 20% interest in its

Verkhnechonskneftegaz subsidiary to the Beijing Gas Group in
November. The parties are in the process of obtaining the necessary
regulatory approvals.

Market price
The price of Urals delivered in North West Europe (Rotterdam) averaged
$41.68/bbl in 2016, $2.05/bbl below dated Brent . The differential
to Brent widened from $1.42/bbl in 2015, amid increased supplies of
competing medium sour crude from the Middle East.

Financial results
Replacement cost (RC) profit before interest and tax for the segment
for 2016 and 2014 included non-operating gains of $23 million and
$225 million respectively whereas the 2015 result did not include any
non-operating items.

After adjusting for non-operating items, the decrease in the underlying
RC profit before interest and tax compared with 2015 primarily reflected
lower oil prices and increased government take, partially offset by
favourable duty lag effects. Compared with 2014, the 2015 result
primarily was affected by lower oil prices and foreign exchange, partially
offset by favourable duty lag effects. See also Financial statements –
Notes 16 and 31 for other foreign exchange effects.

Balance sheet

2016

2015

$ million
2014

• Signing an agreement for the purchase of a 49% stake in Essar Oil

Investments in associates c

(as at 31 December)

8,243

5,797

7,312

Production and reserves

Production (net of royalties)

(BP share)
Liquids (mb/d)
Crude oild
Natural gas liquids
Total liquids

Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)
Estimated net proved reservese
(net of royalties) (BP share)

Liquids (million barrels)

Crude oild
Natural gas liquids
Total liquids

Natural gas (billion cubic feet)
Total hydrocarbons (mmboe)

2016

2015

2014

836
4
840
1,279
1,060

809
4
813
1,195
1,019

5,330
65
5,395f
11,900g
7,447

4,823
47
4,871
11,169
6,796

816
5
821
1,084
1,008

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

c See Financial statements – Note 16 for further information.
d Includes condensate.
e Because of rounding, some totals may not agree exactly with the sum of their
component parts.
f Includes 347 million barrels of crude oil in respect of the 6.58% non-controlling interest in
Rosneft held assets in Russia including 28 million barrels held through BP’s equity-accounted
interest in Taas-Yuryakh Neftegazodobycha.
g Includes 300 billion cubic feet of natural gas in respect of the 2.53% non-controlling
interest in Rosneft held assets in Russia including 3 billion cubic feet held through BP’s
equity-accounted interest in Taas-Yuryakh Neftegazodobycha.

Limited (EOL), an Indian downstream business, from the Essar group
in October. As a result of this transaction, Rosneft will acquire an
interest in the Vadinar refinery and related infrastructure in India, which
is among the top 10 refineries in terms of scale and complexity
worldwide. EOL’s business also includes a network of Essar-branded
retail outlets across India. The parties are in the process of obtaining
the necessary regulatory approvals.

• Signing an agreement for the acquisition of 30% of the concession
agreement for the development of the Zohr gas field in Egypt in
December for $1.125 billion plus $450 million as reimbursement of
2016 historical expenses. The agreement also includes an option for
Rosneft to acquire an additional 5% interest on the same terms. The
parties are in the process of obtaining the necessary regulatory
approvals.

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, representing BP’s 19.75% share of the profit or loss of
Rosneft, as adjusted 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. See
Financial statements – Note 16 for further information.

Profit before interest and taxa b
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)

2016
643
(53)
590

(23)

2015
1,314
(4)
1,310

$ million
2014
2,076
24
2,100

–

(225)

567

1,310

1,875

41.68

50.97

$ per barrel
97.23

a 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.
b Includes $3 million (2015 $16 million, 2014 $25 million) of foreign exchange losses arising on
the dividend received.

See Glossary.

BP Annual Report and Form 20-F 2016
Other businesses and corporate

Comprises our alternative energy business,
shipping, treasury and corporate activities,
including centralized functions and the costs
of the Gulf of Mexico oil spill.

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Gulf of Mexico oil spill
Following the 2015 settlements with the United States
and the Gulf states, that were approved by the federal
district court in 2016, further significant progress was
made in 2016 towards resolving outstanding claims
arising from the 2010 Deepwater Horizon accident and
oil spill.

This included:

• Progress in resolving the outstanding business

economic loss claims under the Plaintiffs’ Steering
Committee (PSC) settlement.

• Progress in resolving economic loss and property

damage claims from individuals and businesses that
either opted out of the PSC settlement and/or were
excluded from that settlement.

• The finalization by the claims administrator of six of the

claims categories under the PSC settlement, the
largest of which was the seafood compensation
programme.

• The settlement of the class action brought by ADS

holders who purchased their shares after the accident.

As a result of this progress, we have clarified the
remaining material uncertainties arising from the
incident.

The cumulative pre-tax income statement charge since
the incident, in April 2010, amounted to $62.6 billion.

More information

Financial statements Note 2.
Process safety and ethics monitors page 42.
Legal proceedings page 261.

Financial performance

2016

2015

$ million
2014

Sales and other operating

revenuesa

1,667

2,048

1,989

RC profit (loss) before

interest and tax

Gulf of Mexico oil spill
Other
RC profit (loss) before

(6,640) (11,709)
(1,768)
(1,517)

(781)
(2,010)

interest and tax

(8,157) (13,477)

(2,791)

Net unfavourable impact
of non-operating items

Gulf of Mexico oil spill
Other
Net charge (credit) for
non-operating items
Underlying RC profit (loss)
before interest and tax
Organic capital expenditure
Additions to non-current

6,640
279

11,709
547

781
670

6,919

12,256

1,451

(1,238)
251

(1,221)
340

(1,340)
903

assets

216

315

784

a Includes sales to other segments.

The replacement cost (RC) loss before interest and tax
for the year ended 31 December 2016 was $8.2 billion
(2015 $13.5 billion, 2014 $2.8 billion). The 2016 result
included a net charge for non-operating items of $6,919
million primarily relating to costs for the Gulf of Mexico
oil spill (2015 $12,256 million, 2014 $1,451 million).
For further information, see Gulf of Mexico oil spill and
Financial statements – Note 2.

After adjusting for these non-operating items, the
underlying RC loss before interest and tax for the year
ended 31 December 2016 was $1.2 billion, similar to prior
years (2015 $1.2 billion, 2014 $1.3 billion).

Outlook
Other businesses and corporate annual charges,
excluding non-operating items, are expected to be
around $1.4 billion in 2017.

Main image: The fermentation
tanks at our biofuels Ituiutaba
sugar cane to ethanol plant
in Brazil.

Inset image: An engineer at the
top of a wind turbine tower at
Sherbino wind farm in Texas.

See Glossary.

BP Annual Report and Form 20-F 2016

Our Tropical site achieved the Bonsucro certification for
sustainability, legal compliance and production processes for the
fourth consecutive year.

We produced 733 million litres of ethanol equivalent and generated
562GWh of power for Brazil’s national grid.

We continue to invest in the development and commercialization of
biobutanol, in conjunction with our partner, DuPont. Compared with
other biofuels, biobutanol has the potential to be blended with fuels
in higher proportions and be easier to transport, store and manage.
We are also investigating a number of chemical applications for this
advanced biofuel.

Wind
BP is among the top wind energy producers in the US. At
31 December 2016, we directly operated 14 wind farms across
eight US states, while holding an interest in a separate facility in
Hawaii. Our net generating capacity from this portfolio, based
on our financial stake was 1,452MW of electricity.

Our net share of US wind generation for 2016 was 4,389GWh.

BP also runs one wind farm at our refinery sites in the Netherlands,
operating on a much smaller scale and managed by our
Downstream segment, with 22.5MW of generating capacity.

Safety remains our number one priority and a number of sites
achieved safety milestones in 2016. For example, Silver Star and
Titan both achieved seven years without a recordable injury, and
Fowler 1 and 3 have received awards from Vestas – a leading wind
turbine manufacturer – for ‘best overall balanced scorecard’ which
includes metrics for safety and availability.

Alternative energy

BP has the largest operated renewables
business among our oil and gas peers.
Renewables will play an increasingly important role in a lower carbon
future. They are projected to grow seven times faster than all other
energy types combined. Today, they account for around 3% of global
energy demand, excluding large-scale hydroelectricity.

BP has been producing renewable energy for more than a decade.
Our strategy is to invest where we can build commercially viable
businesses at scale. With a focus on biofuels and wind, we have the
largest operated renewables business among our oil and gas peers.
This means that we are directly managing these businesses – from
manufacturing biofuels from sugar cane feedstock to generating and
distributing wind energy.

We are also evaluating other areas where we can grow our involvement
in lower carbon opportunities, particularly where they may play a role in
complementing existing businesses such as natural gas.

Find out about the actions we are taking to address climate change
including low carbon venturing on pages 12 and 43.

Biofuels business model and strategy
Biofuels can help reduce emissions from transportation, the fourth
largest source of greenhouse gas (GHG) emissions today. They can
be used in existing cars and infrastructure without major changes.
BP is working to produce biofuels that are low cost, low carbon,
scalable and competitive without subsidies.

Our main activity is in Brazil where we operate three bioethanol sites
with a combined nameplate capacity of 10 million tonnes per year.
We also export power made from sugar cane waste to the local grid.
We use our expertise and technology capabilities to drive continuing
improvements in operational efficiency.

Our strategy is enabled by:

• Safe and reliable operations – continuing to drive improvements

in personal, process and transport safety.

• Competitive sourcing – concentrating our efforts in Brazil, which
has one of the most cost-competitive biofuel feedstocks currently
available in the world.

• Low carbon – producing bioethanol supported by low carbon power
generated from burning sugar cane waste. These processes reduce
life cycle GHG emissions by around 70% compared with gasoline.

• Domestic and international markets – selling bioethanol

domestically in Brazil and also to international markets such as the
US and Europe through our integrated supply and trading function.

Caption: Producing biofuels from sugar
cane at our Tropical site in Brazil.

More information

See bp.com/renewables or our Sustainability Report.

BP Annual Report and Form 20-F 2016Caption: Our British Merchant LNG
tanker was built in 2003 and measures
279 metres in length.

Shipping
BP’s shipping and chartering activities help to ensure the safe
transportation of our hydrocarbon products using a combination of BP-
operated, time-chartered and spot-chartered vessels. At 31 December
2016, BP had four vessels supporting operations in Alaska, and 46 BP-
operated and 28 time-chartered vessels for our international oil and gas
shipping operations. In 2016 13 new oil tankers were delivered into the
BP-operated fleet, a further 13 are expected in 2017, and six technically
advanced LNG tankers are on order and planned for delivery into the BP-
operated fleet between 2018 and 2019.

As part of our fleet rejuvenation programme, the new ships will all
be equipped with new technologies that help improve their safety,
efficiency and emissions. For example tankers and product carriers are
built with extra-long stroke engines that reduce fuel consumption with
fewer revolutions per minute. And within the fleet certain ships have
low enough sulphur dioxide emissions to enable us to trade in parts of
the world with the most stringent regulations. All vessels conducting
BP shipping activities are required to meet BP approved health, safety,
security and environmental standards.

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 funding and
investment, and financial institution credit risk. From locations in the
UK, 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 28.

Insurance
The group generally restricts its purchase of insurance to situations
where this is required for legal or contractual reasons. Some risks are
insured with third parties and reinsured by group insurance companies.
This approach is reviewed on a regular basis or if specific circumstances
require such a review.

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performanceSustainability

We aim to create long-term value for our
shareholders, partners and society by helping to
meet growing energy demand in a safe and
responsible way.

In summary

Our 2016 sustainability focus

These sustainability issues are the ones that
could impact our business the most and that
are of greatest interest to our stakeholders.

Safety

Safety is one of our values and our number one
priority. Our stated aim is to have no accidents, no
harm to people and no damage to the environment.

The fundamentals of how we deliver safe and reliable
operations remain unchanged in a lower oil price
environment. We are working to continuously improve
personal and process safety and operational risk
management across BP, with our group-wide operating
management system at its core. Our approach builds
on our experience, including learning from incidents,
operations audits, annual risk reviews and sharing
lessons learned with our industry peers.

In 2016 BP reported three workforce fatalities. One
contractor died following a leg injury sustained at our
biofuels business in Brazil and two contractors died in
a pipeline construction incident in Oman. We deeply
regret the loss of these lives and continue to focus our
efforts on eliminating the risk of injuries and fatalities in
our work.

Process safety
Major accidents or spills can result in serious harm to
people and the environment, which is why process
safety is so important. Process safety means designing
our facilities to appropriate standards and using robust
engineering principles. It also underlines the importance
of having capable people and rigorous operating and
maintenance practices.

See bp.com/sustainability
for case studies, country
reports and an interactive
tool for health, safety
and environmental data.

Main image: Mad Dog platform
in the Deepwater Gulf of
Mexico.

Inset image: Two of our wind
farms achieved seven years
without a recordable injury
in 2016.

Safety

Climate change

Value to society

Human rights

Local
environmental
impacts

Ethical conduct

Our people

Process safety events
(number of incidents)

400

300

200

100

2012

2013

2014

2015

2016

Tier 1

Tier 2

Loss of primary containment

Recordable injury frequency
(workforce incidents per 200,000 hours worked)

0.8

0.6

0.4

0.2

Workforce
Employees
Contractors

2012
0.35
0.26
0.43

2013
0.31
0.25
0.36

2014
0.31
0.27
0.34

2015
0.24
0.20
0.28

2016
0.21
0.19
0.22

American Petroleum Institute US benchmarka
International Association of Oil & Gas Producers benchmarka

aAPI and OGP 2016 data reports are not available until May 2017.

BP Annual Report and Form 20-F 2016Tier 1 process safety events
Tier 2 process safety events
Loss of primary containment –

number of incidentsa

Oil spills – numberb
Oil spills contained
Oil spills reaching land and water
Oil spilled – volume (thousand litres)
Oil unrecovered (thousand litres)

2016
16
84

275
149
91
58
677
311

2015
20
83

235
146
91
55
432
142

2014
28
95

286
156
93
63
400
155

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

To track our safety performance we use industry metrics, such as the
American Petroleum Institute recommended practice 754 and the
International Association of Oil and Gas Producers recommended
practice 456. These include tier 1 process safety events, which are
losses of primary containment of greater consequence – such as causing
harm to a member of the workforce, costly damage to equipment
or exceeding defined quantities. Tier 2 events are those of lesser
consequence. The overall number of process safety events decreased in
2016, continuing the downward trend of the past five years.

Another metric that tracks unplanned or uncontrolled releases of our
products from pipes, containers or vehicles is loss of primary containment
(LOPC). This is a BP metric that includes events within our operational
boundary, excluding releases of non-hazardous substances such as
water. We saw an increase of LOPCs in 2016, partly due to harsher winter
operating conditions in our unconventional gas operations in the US.

We have seen improvements in our process safety performance
over the past five years. For example, at our Rotterdam refinery the
number of tier 2 events has reduced from 12 in 2012 to just one in 2016.
Alongside this, the refinery’s availability has increased, with 2016 its
best year in over a decade. We see examples of this right across our
operations – we believe this shows that the rigour needed to produce
safe operations tends also to produce reliable operations.

Personal safety
All members of our workforce have the responsibility and the authority to
stop unsafe work. Our golden rules of safety guide our workers on staying
safe while performing tasks with the potential to cause most harm. The
rules are aligned with our operating management system and focus on
areas such as working at heights, lifting operations and driving safety.

Recordable injury frequencyc
Day away from work case

frequencyc d

Severe vehicle accident ratee

2016
0.21

0.051
0.05

2015
0.24

0.061
0.11

2014
0.31

0.081
0.13

c Incidents per 200,000 hours worked.
d Incidents that resulted in an injury where a person is unable to work for a day (shift) or more.
e This figure is based on our new definition which aligns with industry practice. We estimate
that based on our previous definition, the rate would have been around 0.09%.

We monitor and report on key workforce personal safety metrics and
include both employees and contractors in our data.

We measure our workforce recordable injury frequency, which is the
number of reported work-related incidents that result in a fatality or
injury per 200,000 hours worked. We also measure our day away from
work case frequency, which is the number of incidents per 200,000
hours worked that resulted in an injury where a person is unable to work
for a day (or shift) or more.

Our recordable injury frequency and our day away from work rates have
reduced across BP in 2016. This continues a pattern of improvement in
personal safety over a number of years, which is encouraging. However
we know we must maintain our efforts to continue improving safety in
our operations.

Caption: Using technology to monitor
conditions on board our Thunder Horse
platform in the Gulf of Mexico.

Managing safety
BP-operated businesses are responsible for identifying and managing
operating risks and bringing together people with the right skills and
competencies to address them. They are required to carry out
self-verification and are also subject to independent scrutiny and
assurance. Our safety and operational risk team works alongside
BP-operated businesses to provide oversight and technical guidance,
while our group audit team visits sites on a risk-prioritized basis,
including third-party drilling rigs, to check how they are managing risks.

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 How we manage risk on page 47 and SEEAC’s
report on page 74.

Operating management system
BP’s OMS is a group-wide framework designed to help us manage
risks and drive performance improvements in BP-operated businesses.
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.

We review and amend our group requirements within OMS from time
to time to reflect BP’s priorities and experience. Any 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 activities. All businesses
covered by OMS undertake an annual performance improvement cycle
and assess alignment with the applicable requirements of the OMS
framework. Recently acquired operations need to transition to OMS. See
page 42 for information about contractors and joint arrangements .

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performance

Technology
New technologies are helping us increase the amount and quality of data
we gather from our operations and speed up our analysis, allowing us to
act more quickly. For example, we are piloting software that identifies
early warning signs of potential performance problems by gathering
machinery and plant data, analysing it and bringing it all to a single
screen so engineers can more quickly troubleshoot and resolve potential
issues. See page 12 for more information.

We are also testing magnetic crawler robots to inspect the pipelines that
connect our deepwater wells with our platforms in the Gulf of Mexico.
The robots use lasers to identify corrosion or damage. This can provide
us with earlier warnings of potential safety issues.

Emergency preparedness and response
The scale and spread of BP’s operations means we must be prepared to
respond to a range of possible disruptions and emergency events. We
maintain disaster recovery, crisis and business continuity management
plans and work to build day-to-day response capabilities to support local
management of incidents.

Working with contractors and partners
With more than half the hours worked in BP carried out by contractors,
our ability to be a safe operator depends in part on the capability and
performance of those who help us carry out our work. We seek to set
clear and consistent expectations of our contractors. Our standard
model contracts include health, safety, security, human rights 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 a site.

We expect and encourage our contractors and their employees
to act in a way that is consistent with our code of conduct and we
take appropriate actions where we believe they have not met our
expectations or their contractual obligations. Our OMS includes
requirements and practices for working with contractors.

Our partners in joint arrangements
In joint arrangements where we are the operator, our OMS, code of
conduct and other policies apply. We aim to report on all aspects of
our business where we are the operator – as we directly manage the
performance of these operations.

Security
BP monitors for hostile actions that could cause harm to our people
or disrupt our operations. We assess risk on an ongoing basis in those
areas that are affected by political and social unrest, terrorism, armed
conflict or criminal activity. Our central security team provides guidance
and support to our businesses through a network of regional security
advisers.

Oil spill response
Our requirements for oil spill preparedness and response planning
incorporate what we have learned over many years of operations. We
take steps to improve our ability to respond to spills. For example, we
used satellite technology to enhance our response in the UK North Sea
in 2016.

Where we are not the operator, our OMS is available as a reference
point for BP businesses when engaging with operators and
co-venturers. We monitor performance and how risk is managed in our
joint arrangements, whether we are the operator or not. For example, in
Canada we have 50% ownership of the Sunrise oil sands project but it
is operated by another company. We benchmark the operator’s safety,
financial and environmental performance against our expectations.
And BP representatives on the venture’s governance committee
are responsible for confirming that activities are consistent with our
investment requirements and code of conduct.

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

Cyber security
Cyber attacks present a risk to the security of our information, IT
systems and operations. We maintain a range of defences to help
prevent and respond to this threat, including a 24-hour monitoring centre
in the US and employee cyber awareness programmes. See page 48.

Process safety and ethics monitors
Two independent monitors – an ethics monitor and a process safety
monitor – were appointed under the terms of the plea agreement that
BP reached with the US government in 2012, following the Deepwater
Horizon accident in 2010. The ethics monitor was also appointed
under the terms of an administrative agreement reached with the US
Environmental Protection Agency in 2014. Under the terms of both
agreements, we are taking additional actions to further enhance ethics
and compliance across BP and the safety of our drilling operations in the
Gulf of Mexico.

The agreements have terms of five years and we are working
closely with the monitors who will review ongoing progress until the
agreements end.

Caption: Monitoring activities
at our office in Cairo, Egypt.

BP Annual Report and Form 20-F 2016Climate change
Working with others, BP can help drive the transition to a lower
carbon future.

Calling for a price on carbon

BP believes that carbon pricing by governments is the most
comprehensive and economically efficient policy to limit GHG
emissions. We assess how potential carbon policy could affect our
businesses now and in the future.

To help anticipate greater regulatory requirements for GHG
emissions, we factor a carbon price into our own investment
decisions and engineering designs for large new projects and those
for which emissions costs would be a material part of the project.
In industrialized countries, this is currently $40 per tonne of CO2
equivalent and we also stress test at a carbon price of $80 per tonne.

Supplying natural gas

Around half of BP’s upstream portfolio is currently natural gas, which
produces about half as much GHG emissions as coal when burned
to generate power. We have several new big gas projects coming
onstream in the next few years including Khazzan in Oman, West
Nile Delta and Zohr in Egypt, Juniper in Trinidad and the Southern Gas
Corridor from the Caspian Sea to Europe.

Providing renewable energy

BP invests in renewable energy where we can build commercially
viable businesses at scale. With a focus on biofuels and wind, we have
the largest operated renewables business among our oil and gas peers.

Pursuing efﬁcient operations

We are focusing on ways to reduce our GHG emissions. This includes
looking to improve the energy efficiency of our operations and
reducing flaring and methane emissions.

Investing in start-ups and innovation

Over the past decade, we have invested in start-up companies to
help accelerate development and commercial viability of certain
technologies. As at 31 December 2016, we had invested around $300
million in emerging technology companies – around half of these
investments focus on low carbon solutions.

Helping customers reduce their emissions

BP provides an increasing number of lower carbon, energy-efficient
and high-performance products to help our customers reduce their
carbon footprint – from Castrol lubricants with lower viscosity, which
helps manufacturers improve the efficiency of their vehicles – to
PTAir – PTA with around a 30% lower carbon footprint than average
European production.

We are collaborating with others to help address this global challenge.
As one example, the Oil and Gas Climate Initiative – currently chaired
by our chief executive Bob Dudley – brings together 10 oil and gas
companies working to reduce the GHG emissions from our industry’s
operations and the use of our products.

See bp.com/climatechange for more information.

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.

Our approach to reporting GHG emissions broadly follows the
IPIECA/API/IOGP Petroleum Industry Guidelines for Reporting GHG
Emissions. We calculate emissions based on the fuel consumption
and fuel properties for major sources rather than the use of generic
emission factors. We do not include nitrous oxide, hydrofluorocarbons,
perfluorocarbons and sulphur hexafluoride as they are not material and it
is not practical to collect this data.

Greenhouse gas emissionsab
(MteCO2 equivalent)

49.0

0.3

G
H
G

t
c
e
r
i
d
5
1
0
2

s
n
o
i
t
i
s
u
q
c
A

-0.4

s
t
n
e
m
t
s
e
v
D

1.5

50.1

-0.3

s
e
g
n
a
h
c

a
n
o
i
t
a
r
e
p
O

e
b
a
n
a
t
s
u
s

a
e
R

s
n
o
i
t
c
u
d
e
r

G
H
G
t
c
e
r
i
d
6
1
0
2

a This is based on BP’s equity share basis (excluding BP’s share of Rosneft).
b A minor adjustment has been made from the reported 2015 figure of 48.9.

Our direct GHG emissions are impacted year-on-year by changes in our
portfolio and operations. For example, emissions can increase when
we start up new projects or when we bring operations back online after
planned maintenance. Both of these activities are essential for the safe
performance and growth of BP’s portfolio. In 2016, the increase in our
direct GHG emissions was primarily due to operational changes that
include the start-up activities of the Sunrise oil sands project in Canada
and the LNG plant in Angola. And one of our US refineries restarted
operations following a planned shutdown for maintenance. Around a
quarter of the increase is due to changes in how we calculate emissions.

This increase has been partially offset by our ‘real sustainable
reductions’ – these are actions taken by our businesses to permanently
reduce their GHG emissions in areas such as flaring, methane and
energy efficiency. We began tracking this in 2002, and the running total
by the end of 2016 exceeded 9.1Mte.

Greenhouse gas emissions (MteCO2e)

Operational controla
Direct emissions
Indirect emissions
BP equity sharec
Direct emissions
Indirect emissions

2016

2015

2014

51.4
6.2

50.1
6.2

51.2b
7.0

49.0d
6.9

54.1
7.5

48.7e
6.8

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.
b A minor adjustment has been made from the reported 2015 figure of 51.4.
c BP equity share comprises our share of BP’s consolidated entities and equity-accounted
entities, other than BP’s share of Rosneft.
d A minor adjustment has been made from the reported 2015 figure of 48.9.
e A minor adjustment has been made from the reported 2014 figure of 48.6.

The ratio of our total GHG emissions reported on an operational control
basis to gross production was 0.24teCO2e/te production in 2016 (2015
0.24teCO2e/te, 2014 0.25teCO2e/te). Gross production comprises
upstream production, refining throughput and petrochemicals produced.

BP Annual Report and Form 20-F 2016Strategic report – performance

Value to society
We aim to have a positive and enduring impact on the communities
in which we operate.

We contribute to economies through our core business activities, such
as helping to develop the national and local supply base, and through the
taxes we pay to governments. Additionally, our social investments support
communities’ efforts to increase their incomes and improve standards of
living. For example, in Egypt we support healthcare in the communities
that are closest to our West Nile Delta project by funding emergency
equipment for local hospitals.

We run programmes to help build the skills of businesses and develop
the local supply chain in a number of locations. In Angola, for example, we
have supported the foundation of local businesses, providing community
members with technical and hands-on training. Our enterprise and
development programme in Azerbaijan helps local companies build their
skills so that they can improve their competitiveness when bidding for
work with international firms.

We aim to recruit our workforce from the community or country in which
we operate. At our Tangguh LNG plant in West Papua, Indonesia, more
than half of our workforce is Papuan. This is a direct result of internship and
apprentice programmes that focus on training graduates from Papua and
Papua Barat. We are committed to reaching an 85% Papuan workforce by
2029.

We contributed $61.1 million in social investment in 2016.

See bp.com/society for more information on how we are maximizing value
to society.

Tax and ﬁnancial transparency
We contribute to economies around the world through the taxes that we
pay. We paid $2.2 billion in income and production taxes to governments in
2016 (2015 $3.5bn, 2014 $8.0bn).

BP is committed to complying with tax laws in a responsible manner
and having open and constructive relationships with tax authorities. We
participate in initiatives to simplify and improve tax regimes to encourage
investment and economic growth. We also support efforts to increase public
trust in tax systems.

The Extractive Industries’ Transparency Initiative (EITI) supports disclosure
of payments made to, and received by, government in relation to oil, gas
and mining activity. As a member of EITI, BP works with governments,
non-governmental organizations and international agencies to improve the
transparency of payments to governments.

BP discloses information on payments to governments for our upstream
activities. We report on a country-by-country and project basis as required
by UK regulation which incorporates the EU Accounting Directive. These
payments could be made in the form of production entitlements, taxes,
royalties, bonuses, fees and infrastructure improvements. We also make
payments to governments in connection with other parts of our business –
such as the transporting, trading, manufacturing and marketing of oil and gas.

See bp.com/tax for our approach to tax and our payments to governments
report.

Human rights
We strive to conduct 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 and our code of
conduct. Through our code of conduct, employees are required to report
any human rights abuse in either our operations or those of our business
partners.

Caption: Operations at the Rumaila oil
field in southern Iraq.

We are working towards alignment with the UN Guiding Principles on
Business and Human Rights by implementing our human rights policy.
Our focus is on identifying and addressing human rights risks, including
those associated with the recruitment and living conditions of contracted
workforces on our sites, and on enhancing community grievance
mechanisms and channels for workforces to raise their concerns.

In 2016 our actions included:

• Initiation of a review examining the risk of modern slavery, focusing on

the parts of our business and supply chain where we believe there could
be greater risk.

• Development and piloting of a human rights due diligence process that
can be used to screen suppliers in a consistent way anywhere in the
world.

• Evaluation of key sites’ community complaints mechanisms against the
Guiding Principles to identify good practice and areas for improvement.

• Continued implementation of the Voluntary Principles on Security and
Human Rights, with periodic internal assessments to identify areas for
improvement.

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

Local environmental impacts
We work to avoid, minimize and mitigate environmental impacts
from our activities.

We consider local conditions when determining which issues would benefit
from the greatest focus. At a site close to communities, for example, the
immediate concern may be air quality, whereas a remote desert site may
require greater consideration of water management issues.

Water
BP recognizes the importance of managing freshwater use and water
discharges in our operations and we review our water risks annually.
We consider the local environment and quantity, quality and regulatory
impacts. We assess different approaches for optimizing water
consumption and wastewater treatment performance. For example, at
our Khazzan operation in Oman, we treat wastewater from our sewage
treatment plant and re-use it for irrigation, road construction and dust
suppression, reducing freshwater demand in an area of water scarcity.

BP Annual Report and Form 20-F 2016We monitor the increasing number of regulations pertaining to
freshwater withdrawals and water discharge quality where we operate.
This has led to investments in our wastewater treatment plants at our
refineries in Germany and the US.

Ethical conduct
Our code of conduct deﬁnes our commitment to high ethical
standards.

See bp.com/water for information about our approach to water.

Our values

Air quality
We put measures in place to manage our air emissions, in line with
regulations and guidelines designed to protect the environment and the
health of local communities.

For example, our Whiting refinery is one of the largest refineries in the
US, with the potential to have a significant impact on local air quality. We
have reduced our air emissions there by more than 50% over the past
five years by minimizing the amount of gas flared and emissions from
process equipment. We monitor sulphur dioxide, hydrogen sulphide,
benzene and other pollutants at the periphery of the refinery and make
this data available on the refinery’s website.

Unconventional gas and hydraulic fracturing
Some stakeholders have raised concerns about the potential
environmental and community impacts of hydraulic fracturing during
unconventional gas development. BP seeks to apply responsible well
design practices to mitigate these risks. For example, our wells are
designed, constructed, operated and decommissioned to prevent gas
and hydraulic fracturing fluids entering underground aquifers, such as
drinking water sources.

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 are working to minimize air pollutant and GHG emissions, such as
methane, at our operating sites. At our Khazzan site in Oman we have
built a central processing facility that reduces the need for processing
equipment at each individual well site, which can be additional sources
of methane emissions in gas production. In the US we use a process
called green completions at our gas operations. This process captures
natural gas that would otherwise be flared or vented during the
completion and commissioning of wells.

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

Caption: Safety checks at Cherry
Point refinery, US.

Safety

Respect

Excellence

Courage

One Team

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.

The BP code of conduct
Our code of conduct is based on our values and clarifies the principles
and expectations for how we work at BP. It applies to all BP employees
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 is potentially
unsafe, unethical or harmful can discuss these with their managers,
supporting teams, works councils (where relevant) or through OpenTalk,
a confidential helpline operated by an independent company.

A total of 956 people contacted OpenTalk with concerns or enquiries in
2016 (2015 1,158, 2014 1,114). 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 2016 our businesses
dismissed 109 employees for non-conformance with our code of
conduct or unethical behaviour (2015 132, 2014 157). This excludes
dismissals of staff employed at our retail service stations.

See bp.com/codeofconduct for more information.

Anti-bribery and corruption
Bribery and corruption are significant risks in the oil and gas industry.
We have a responsibility to our employees, our shareholders and to the
countries and communities in which we do business to be ethical and
lawful in all our work. Our code of conduct explicitly prohibits engaging
in bribery or corruption in any form.

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

BP Annual Report and Form 20-F 2016Strategic report – performanceLobbying and political donations
We prohibit the use of BP funds or resources to support any political
candidate or party.

We recognize the rights of our employees to participate in the political
process. Their rights to do so are governed by the applicable laws in
the countries in which we operate. For example, in the US we support
the operation of the BP employee political action committee (PAC),
which is a non-partisan committee that encourages voluntary employee
participation in the political process. All BP employee PAC contributions
are reviewed for compliance, comply with the law and are publicly
reported in accordance with US election laws.

The way in which we interact with governments depends on the legal
and regulatory framework in each country. We engage across a range
of issues that are relevant to our business, from regulatory compliance,
to understanding our tax liabilities, to collaborating on community
initiatives.

Our people
BP’s success depends on having a highly skilled and motivated
workforce that reflects the societies where we operate.

BP employees
Number of employees at 31 Decembera
Upstream
Downstream
Other businesses and corporate
Total
Service station staff
Agricultural, operational and
seasonal workers in Brazil
Total excluding service station
staff and workers in Brazil

2016
18,700
41,800
14,000
74,500
16,200

2015
21,700
44,800
13,300
79,800
15,600

2014
24,400
48,000
12,100
84,500
14,400

4,600

4,800

5,300

53,700

59,400

64,800

a Reported to the nearest 100. For more information see Financial Statements – Note 34.

A lower oil price has meant that we have continued to adapt and reshape
our organization. This has contributed to a reduction in overall headcount
of 10,000 over the past two years. Our focus is on retaining the skills we
require to maintain safe and reliable operations.

The group people committee helps facilitate the group chief executive’s
oversight of policies relating to employees. In 2016 the committee
discussed longer-term people priorities, reward, progress in our diversity
and inclusion programme, employee engagement, and improvements to
our training and development programmes.

Attracting and retaining the right people
We prefer building capability and promoting people from within
our organization and we complement this with selective external
recruitment for specialist roles.

We provide on-the-job learning and mentoring programmes, as
well as online and classroom-based courses. Structured leadership
courses help employees move into more senior positions. Our average
expenditure on learning and development was around $4,000 per
person in 2016 (2015 $4,000).

We continued to invest in graduate recruitment and early career
recruitment in 2016, albeit at a reduced level. A total of 231 global
graduates joined BP in 2016 (2015 298, 2014 670). We are working to
increase our visibility in the graduate job market and in 2016, students
voted us the UK’s Most Popular Graduate Recruiter in the energy and
utilities sector at the Target Jobs Sector Awards.

Diversity
We are a global company and aim for a workforce that is representative
of the societies in which we operate.

Our gender balance is steadily improving, with women representing
33% of BP’s population and 22% of group leaders – our most senior
managers – at the end of 2016. Our aim is for women to represent at
least 25% of group leaders by 2020. Following the retirement of our
executive vice president of corporate business activities in 2016, we are
considering how best to increase female representation at executive
level.

At the end of 2016 there were three female directors (2015 3, 2014 2) on
our board. Our nomination committee remains mindful of diversity when
considering potential candidates.

For more information on the composition of our board, see page 65.

Workforce by gender

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

Male
11
308
1,056
50,200

Female
3
86
174
24,300

Female %
21%
22%
14%
33%

We are also committed to increasing the national diversity of our
workforce to reflect the countries in which we operate. A total of 26% of
our group leaders came from countries other than the UK and the US in
2016 (2015 23%, 2014 22%).

Inclusion
Our goal is to create an environment of inclusion and acceptance, where
everyone is treated equally and without discrimination.

We aim to ensure equal opportunity in recruitment, career development,
promotion, training and reward for all employees – regardless of
ethnicity, national origin, religion, gender, age, sexual orientation, marital
status, disability, or any other characteristic protected by applicable laws.
Where existing employees become disabled, our policy is to provide
continued employment, training and occupational assistance where
needed.

Employee engagement
Managers hold regular team and one-to-one meetings with their staff,
complemented by formal processes through works councils in parts
of Europe. We regularly communicate with employees on factors
that affect company performance, and seek to maintain constructive
relationships with labour unions formally representing our employees.

Our annual employee survey found that confidence in the future
of BP has risen to 64% in 2016 (2015 58%, 2014 63%), with solid
improvements in pride in working for BP and trust in management.

However, scores related to career opportunities, reward and recognition
are not as high as we would like them to be and we will review actions to
address these areas in 2017.

Share ownership
We encourage employee share ownership and have a number of
employee share plans in place. For example, under our ShareMatch
plan, which operates in more than 50 countries, we match BP
shares purchased by our employees. We also operate a group-wide
discretionary share plan, which allows employee participation at
different levels globally and is linked to the company’s performance.

BP Annual Report and Form 20-F 2016How we manage 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 49.

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 and policy 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:

• Understand the risk environment, and assess the specific risks and

potential exposure for BP.

• Determine how best to deal with these risks to manage overall

potential exposure.

• Manage the identified risks in appropriate ways.

• Monitor and seek assurance of the effectiveness of the management

of these risks and intervene for improvement where necessary.

• 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 seek to 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 management 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
designed 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’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.

• Group people committee – for employee risks.

• Group ethics and compliance committee – for legal and regulatory

compliance and ethics risks.

• Resource commitment meeting – for investment decision risks.

Board and its committees

• BP board.

• Audit committee.

• Safety, ethics and environment assurance committee.

• Geopolitical committee.

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 2017 are listed in this section. 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.

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 49.

More information

Risk management and internal control page 111.
Board and committee reports page 64.

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performance
Risks for particular oversight by the board and its
committees in 2017
The risks for particular oversight by the board and its committees in
2017 have been reviewed and updated. These risks remain the same
as for 2016.

Strategic and commercial risks
Financial resilience
External market conditions can impact our financial performance. Supply
and demand and the prices achieved for our products can be affected by
a wide range of factors including political developments, technological
change, global economic conditions and the influence of OPEC.

We actively manage this risk through BP’s diversified portfolio, our
financial framework, liquidity stress testing, regular reviews of market
conditions and our planning and investment processes.

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 and implement risk mitigation plans where
appropriate.

Cybersecurity
The threats to the security of our digital infrastructure continue to evolve
rapidly and, like many other global organizations, we rely on digital
systems and network technology. A cybersecurity breach could have a
significant impact on business operations.

We seek to manage this risk through a range of measures, which include
cybersecurity standards, ongoing monitoring of threats and testing of
cyber response procedures and equipment. We collaborate closely
with governments, law enforcement agencies and industry peers to
understand and respond to new and emerging cyber threats. Campaigns
and presentations on topics such as email phishing and protecting our
information and equipment have helped to raise employee 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.

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.

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 our
businesses through 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 threats globally and, in particular, the situation in the
Middle East, North Africa and Europe.

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 2012 plea
agreement with the US government and the 2014 settlement with the
US Environmental Protection Agency, an ethics monitor is reviewing
and providing recommendations concerning BP’s ethics and compliance
programme.

Trading non-compliance
In the normal course of business, we are subject to risks around our
trading activities which could arise from shortcomings or failures in our
systems, risk management methodology, internal control processes or
employees.

We have specific operating standards and control processes to 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.

Encouraging employees
to think before they click

We rank cybersecurity as one of our highest priority risks. We deal
with attempted cyber attacks on our business every day. Employees
are our first line of defence against these attacks and we promote
secure behaviours to help mitigate this growing risk. We focus on
practical rules that we promote through films, e-learning and sessions
delivered by senior managers and our digital security team.

One of our rules addresses ‘phishing’, which is the attempt to trick
people into revealing sensitive information and can involve installing
malicious software to steal information without their knowledge.
So we remind staff to ‘think before you click’ and be vigilant for
phishing emails, calls and other suspicious requests for information
and to report any such attempts to our digital security operations
centre.

We conduct ‘ethical phishing’ tests to educate our employees in this
area. The number of employees who click on the links in the test
emails has fallen by more than 70% since 2012. Over the same time,
there has been a significant increase in the number of employees
reporting the phishing tests. The programme is driving real change in
awareness, but we remain vigilant as the threat continues to evolve.

BP Annual Report and Form 20-F 2016Risk 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.

Strategic and commercial risks
Prices and markets – our financial performance is subject to fluctuating
prices of oil, gas, refined products, technological change, 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
demand and prices for our products. Decreases in oil, gas or product
prices could have an adverse effect on revenue, margins, profitability
and cash flows. If significant or for a prolonged period, we may have to
write down assets and re-assess the viability of certain projects, which
may impact future 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.

Events in or relating to Russia, including further trade restrictions and other
sanctions, could adversely impact our income and investment in Russia.
Our ability to pursue business objectives and to recognize production and
reserves relating to Russia could also 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 242 and
Financial statements – Note 28.

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.

Digital infrastructure and cybersecurity – breach of our digital
security or failure of our digital infrastructure could damage our
operations and our reputation.
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, policies and obligations relating to climate
change, including carbon pricing, could impact our assets, costs,
revenue generation and strategic growth opportunities and demand for
our products.

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.

See Glossary.

BP Annual Report and Form 20-F 2016Strategic report – performance
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. Some risks are insured with third parties and
reinsured by group insurance companies. 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, extreme weather, 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 40.

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

Drilling and production – challenging operational environments and
other uncertainties can impact drilling and production activities.
Our activities require high levels of investment and are sometimes
conducted in extremely challenging environments which heighten the
risks of technical integrity failure and the impact of natural disasters
and extreme weather. The physical characteristics 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 – failure to comply with the terms of
our settlements with legal and regulatory bodies in the US announced
in November 2012 in respect of certain charges related to the Gulf of
Mexico oil spill may expose us to further penalties or liabilities 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 and expose us to severe penalties,

financial or otherwise, 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 imposed on similar 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. 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, and could result in litigation, regulatory
action and penalties.
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 oversight 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 28.

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.

The Strategic report was approved by the board and signed on its behalf by
David J Jackson, company secretary on 6 April 2017.

See Glossary.

BP Annual Report and Form 20-F 2016Corporate
governance

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52 Board of directors

58 Executive team

60 Executive management teams

Introduction from the chairman
63 Governance framework
63 Board and committee attendance

64 Board activity in 2016
64 Role of the board
65 Skills and expertise
65 Diversity
65
65 Appointment and time commitment
66 Training and induction
66 Board evaluation
67 Field visits

Independence

68 Shareholder engagement
Institutional investors

68
68 Private investors
68 AGM
68 UK Corporate Governance Code Compliance

International advisory board

69 Committee reports
69 Audit committee
74
76 Remuneration committee
78 Geopolitical committee
79 Chairman’s committee
79 Nomination committee

Safety, ethics and environment assurance committee

80 Directors remuneration report

80 Letter from the remuneration committee chair
83 Summary of our pay and performance for 2016
84 Summary of our remuneration policy and approach for 2017
86 Features of 2017 policy
87
90 Single figure table for 2016
91 Pay and performance for 2016
95 Stewardship and regulatory information
101 2017 proposed policy

Implementation of the 2017 policy

111 Directors’ statements

111 Statement of directors’ responsibilities
111 Risk management and internal control
112 Longer-term viability
112 Going concern
112 Fair, balanced and understandable

BP Annual Report and Form 20-F 2016

Board of directors
As at 6 April 2017

See BP’s board governance principles relating
to director independence on page 266.

Carl-Henric Svanberg
Chairman

Bob Dudley
Group chief executive

Dr Brian Gilvary
Chief financial officer

Chair of the nomination and
chairman’s committees; attends
SEEAa, remuneration and
geopolitical committees

Nils Andersen
Independent non-executive
director

Member of the audit and
chairman’s committees

Paul Anderson
Independent non-executive
director

Alan Boeckmann
Independent non-executive
director

Admiral Frank Bowman
Independent non-executive
director

Member of the SEEA, geopolitical
and chairman’s committees

Chair of SEEA committee; member
of the remuneration, nomination
and chairman’s committees

Member of the SEEA,
geopolitical and chairman’s
committees

Cynthia Carroll
Independent non-executive
director

Member of the SEEA,
geopolitical and chairman’s
committees

Ian Davis
Independent non-executive
director

Member of the remuneration,
geopolitical, nomination and
chairman’s committees

Professor Dame Ann Dowling
Independent non-executive
director

Brendan Nelson
Independent non-executive
director

Chair of the remuneration
committee; member of the
SEEA, nomination and
chairman’s committees

Chair of the audit committee;
member of the chairman’s
committee

Paula Rosput Reynolds
Independent non-executive
director

Member of the audit and
chairman’s committees

David Jackson
Company secretary

Sir John Sawers
Independent non-executive
director

Chair of the geopolitical
committee; member of the
SEEA, nomination and
chairman’s committees

Andrew Shilston
Senior independent
non-executive director

Senior independent director
and member of the audit,
remuneration, geopolitical,
nomination and chairman’s
committees

a Safety, ethics and environment
assurance

BP Annual Report and Form 20-F 2016Carl-Henric Svanberg
Chairman

Tenure
Appointed 1 September 2009

Board and committee activities
Chair of the nomination and chairman’s committees; attends the safety,
ethics and environment assurance, remuneration and geopolitical
committees

Outside interests
• Chairman of AB Volvo

Age 64 Nationality Swedish

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

He spent his early career at Asea Brown Boveri and the Securitas Group,
before moving to the Assa Abloy Group as president and chief executive
officer.

From 2003 until 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 in 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 is a highly experienced leader of global
corporations. He has served as chief executive officer and chairman
to several high profile businesses, leading them through both periods
of growth and restructuring. These experiences bring not only a deep
understanding of international strategic and commercial issues, but the
skills to co-ordinate the diverse range of knowledge and perspectives
provided by the board. He therefore enables the board to present clear
and united leadership on behalf of shareholders.

Carl-Henric’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 the Tsinghua Management University Advisory Board,

Beijing, China

• Member of the BritishAmerican Business International Advisory Board
• Member of the US Business Council
• Member of the US Business Roundtable
• Member of the UAE/UK CEO Forum
• Member of the Emirates Foundation Board of Trustees
• Member of the World Economic Forum (WEF) International

Business Council

• Chair of the WEF Oil and Gas Climate Initiative
• Member of the Russian Geographical Society Board of Trustees
• Fellow of the Royal Academy of Engineering

Age 61 Nationality American and British

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 he was executive assistant to the group
chief executive subsequently becoming group vice president for BP’s
renewables and alternative energy activities. In 2002 he became group
vice president responsible for BP’s upstream businesses in Russia, the
Caspian region, Angola, Algeria and Egypt.

From 2003 to 2008 he was president and chief executive officer of
TNK-BP. On his return to BP in 2009 he was appointed to the BP board and
oversaw the group’s activities in the Americas and Asia. Between 23 June
and 30 September 2010, he served as the president and chief executive
officer of BP’s Gulf Coast Restoration Organization in the US. He was
appointed a director of Rosneft in March 2013 following BP’s acquisition
of a stake in Rosneft.

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Relevant skills and experience
Bob Dudley has spent his whole career in the oil and gas industry. During
his tenure as group chief executive, Bob has transformed BP into a safer,
stronger and simpler business. This approach, governed by a consistent
set of values, has guided BP to a position of greater resilience, enabling it to
continue delivering results in an uncertain economic environment. Bob has
demonstrated excellent leadership and vision throughout this process and
continues to develop the group’s strategy to adapt to new challenges ahead.

Bob Dudley’s performance has been considered and evaluated by the
chairman’s committee.

Dr Brian Gilvary
Chief ﬁnancial ofﬁcer

Tenure
Appointed 1 January 2012

Outside interests
• Non-executive director of L’Air Liquide
• Non-executive director of the Navy Board
• Member of the 100 Group Committee
• Visiting professor at Manchester University
• GB Age Group triathlete

Age 55 Nationality British

Career
Dr Brian Gilvary was appointed chief financial officer in January 2012.
The role includes responsibility for tax, planning, treasury, mergers and
acquisitions, investor relations and audit.

He joined BP in 1986 after obtaining a PhD in mathematics from the
University of Manchester. Following a variety of roles in Upstream,
Downstream and trading in Europe and the US, he became 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.

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.

Brian is also accountable for integrated supply and trading, global business
services, information technology activities, procurement and shipping.

BP Annual Report and Form 20-F 2016
Relevant skills and experience
Dr Brian Gilvary has spent his entire career with BP. His broad
experience across the group has given him a deep insight into BP’s
assets and businesses. This knowledge has been invaluable as BP has
implemented its strategy to transform into a ‘value not volume’ based
business and adapt to a low oil price environment.

His strong understanding of finance and trading has been vital in
adjusting capital structures and operational costs while ensuring
the group continues to be capable of meeting new opportunities
going forward.

Brian Gilvary’s performance has been evaluated by the group chief
executive and considered by the chairman’s committee.

Nils Andersen
Independent non-executive director

Tenure
Appointed 31 October 2016

Board and committee activities
Member of the audit and chairman’s committees

Outside interests
• Non-executive director of Unilever Plc and Unilever NV
• Chairman of Dansk Supermarked Group A/S

Age 58 Nationality Danish

Career
Nils Andersen was group chief executive of A.P. Møller-Mærsk from
2007 to June 2016. Prior to this he was executive vice president
of Carlsberg A/S and Carlsberg Breweries A/S from 1999 to 2001,
becoming president and chief executive officer from 2001 to 2007.

Previous roles include non-executive director of Inditex S.A. and
William Demant A/S. He has also served as managing director of Union
Cervecera, Hannen Brauerei and chief executive officer of the drinks
division of the Hero Group.

Nils received his graduate degree from the University of Aarhus.

Relevant skills and experience
Nils Andersen has extensive experience in consumer goods, retail and
logistics, and leading global corporations with integrated operations
worldwide. The skills and knowledge gained in these roles make him
an ideal addition for the board given his experience in marketing, brand
and reputation issues. His specialist logistics awareness also aligns
with BP’s shipping business. His leadership in earlier roles was notable
for the transformation of businesses through focused portfolios, leaner
organizations and increasing competitiveness, as well as increasing
transparency and communication with stakeholders.

Nils’ economics and broad financial background make him well suited
to his role on the audit committee.

Paul Anderson
Independent non-executive director

Tenure
Appointed 1 February 2010

Board and committee activities
Member of the safety, ethics and environment assurance, geopolitical
and chairman’s committees

Outside interests
No external appointments

Age 72 Nationality American

Career
Paul Anderson was formerly chief executive at BHP Billiton and
Duke Energy, where he also served as chairman of the board. Having
previously been chief executive officer and managing director of BHP
Limited and then BHP Billiton Limited and BHP Billiton Plc, he rejoined
these latter two boards in 2006 as a non-executive director, retiring in
January 2010. Previously 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.

Relevant skills and experience
Paul Anderson has spent his career in the energy industry working with
global organizations, and brings the skills of an experienced chairman
and chief executive officer to the board. His specific experience of
driving safety-related cultural change throughout a business has
been invaluable during his tenure as chair of the safety, ethics and
environment assurance committee from 2012 to 2016, and he remains a
valuable member of the committee.

Paul’s experience of business in the US and its regulatory environment
is a great asset to the geopolitical committee.

Alan Boeckmann
Independent non-executive director

Tenure
Appointed 24 July 2014

Board and committee activities
Chair of the safety, ethics and environment assurance committee;
member of the remuneration, nomination and chairman’s committees

Outside interests
• Non-executive director of Sempra Energy
• Non-executive director of Archer Daniels Midland

Age 68 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,
having previously been 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,
the Eisenhower Medical Center 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 has worked in a wide range of industries including
engineering, construction, chemicals and in the energy sector. In
his senior roles he directed the focus of global corporations towards
the advanced technology needed to remain competitive in response
to the growth of the internet, e-commerce and the globalization
of the workforce. At the same time he actively promoted fairness,
transparency, accountability and responsibility in business dealings
at a time when many corporations were struggling with these issues.

BP Annual Report and Form 20-F 2016 This experience as a chairman and chief executive makes Alan ideal to
lead the SEEAC and brings added value to both the remuneration and
nomination committees.

Admiral Frank Bowman
Independent non-executive director

Tenure
Appointed 8 November 2010

Board and committee activities
Member of the safety, ethics and environment assurance, geopolitical
and chairman’s committees

Outside interests
• President of Strategic Decisions, LLC
• Director of Morgan Stanley Mutual Funds
• Director of Naval and Nuclear Technologies, LLP

Age 72 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 served over eight years
as director of the Naval Nuclear Propulsion Program where he was
responsible for the operations of more than 100 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 US CNA military advisory board and has
participated in studies of climate change and its impact on national
security, and on future global energy solutions and water scarcity.
Additionally he was co-chair of a National Academies study investigating
the implications of climate change for naval forces.

Relevant skills and experience
Frank Bowman’s exemplary safety record in running the US Navy’s
nuclear submarine program indicates his deep understanding of process
safety and its implementation in a widely dispersed workforce. Combined
with his specific knowledge of BP’s safety goals from his work on the
BP Independent Safety Review Panel, and his special interest in climate
change, he brings a unique perspective to the board and the SEEAC.

In addition, Frank’s experience of the US and global political and
regulatory systems is a valuable asset to the geopolitical committee.

Cynthia Carroll
Independent non-executive director

Tenure
Appointed 6 June 2007

Board and committee activities
Member of the safety, ethics and environment assurance, geopolitical
and chairman’s committees

Outside interests
• Chair of Vedanta Resources Holding Ltd
• Non-executive director of Hitachi Ltd
• Advisory board member of America Securities LLC

Age 60 Nationality American

Career
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 chief executive of Anglo
American plc, the global mining group, operating in 45 countries with
150,000 employees, and was chairman of De Beers s.a. and Anglo
Platinum Limited. 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. Her leadership experience,
related to enhancing safety in the mining industry, brings a strong
contribution to the work of the SEEAC, as does her understanding of
business strategy in an industry with a long capital return cycle.

Her experience of leading large complex global businesses which
require a high level of interaction with governments, the media and other
stakeholders is an asset to both the board and the geopolitical committee.

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Ian Davis
Independent non-executive director

Tenure
Appointed 2 April 2010

Board and committee activities
Member of the remuneration, geopolitical, nomination and chairman’s
committees

Outside interests
• Chairman of Rolls-Royce Holdings plc
• Non-executive director of Majid Al Futtaim Holding LLC
• Non-executive director of Johnson & Johnson, Inc.
• Non-executive director of Teach for All

Age 66 Nationality British

Career
Ian Davis is senior partner emeritus of McKinsey & Company. He was a
partner at McKinsey for 31 years until 2010 and served as chairman and
managing director between 2003 and 2009.

Ian has a MA in Politics, Philosophy and Economics from Balliol College,
University of Oxford.

Relevant skills and experience
Ian Davis brings significant financial and strategic experience to the
board. He has worked with and advised global organizations and
companies in a wide variety of sectors including oil and gas and the
public sector. This enables him to draw on knowledge of diverse issues
and outcomes to assist the board and, in particular, the remuneration
and nomination committees.

He led the board’s oversight of the response in the Gulf and chaired the
Gulf of Mexico committee from its formation until it was stood down
in 2016. His previous role in the Cabinet Office gives him a unique
perspective on government affairs which is an asset to both the board
and the geopolitical committee.

Corporate governanceBP Annual Report and Form 20-F 2016
Professor Dame Ann Dowling
Independent non-executive director

Tenure
Appointed 3 February 2012

Board and committee activities
Chair of the remuneration committee; member of the safety, ethics
and environment assurance, nomination and chairman’s committees

Outside interests
• President of the Royal Academy of Engineering
• Deputy vice-chancellor and professor of Mechanical Engineering

at the University of Cambridge

• Member of the Prime Minister’s Council for Science and Technology
• Non-executive director of the Department for Business, Energy and

Industrial Strategy (BEIS)

Age 64 Nationality British

Career
Dame Ann Dowling is a deputy vice-chancellor at the University of
Cambridge where she was appointed a professor of mechanical
engineering in the department of engineering in 1993. She was head
of the department of engineering at the University from 2009 to 2014.
Her research is in fluid mechanics, acoustics and combustion, and she
has held visiting posts at MIT and at Caltech. She chairs BP’s technical
advisory committee.

Dame Ann is a fellow of the Royal Society and the Royal Academy of
Engineering and a foreign associate of the US National Academy of
Engineering and the French Academy of Sciences. She has honorary
degrees from fifteen universities, including the University of Oxford, Imperial
College London and the KTH Royal Institute of Technology, Stockholm.

She was elected President of the Royal Academy of Engineering
in September 2014 and in December 2015 was appointed to the
Order of Merit.

Relevant skills and experience
Dame Ann is an internationally respected leader in engineering research
and the practical application of new technology in industry. Her
contribution in these fields has been widely recognized by universities
around the world. Her academic background provides balance to the
board and brings a different perspective to the SEEAC and nomination
committee.

Dame Ann became chair of the remuneration committee in 2015 and
worked tirelessly over the past year to understand key issues with a
large number of major shareholders and their advisers.

Brendan Nelson
Independent non-executive director

Tenure
Appointed 8 November 2010

Board and committee activities
Chair of the audit committee; member of the chairman’s committee

Outside interests
• Non-executive director and chairman of the group audit committee

of The Royal Bank of Scotland Group plc

• Member of the Financial Reporting Review Panel

Age 67 Nationality British

Career
Brendan Nelson is a chartered accountant. He was made a partner of
KPMG in 1984. He served as a member of the UK board of KPMG from
2000 to 2006, subsequently being appointed vice chairman until his

retirement in 2010. At KPMG International he held a number of senior
positions including global chairman, banking and global chairman,
financial services.

He served 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
Over the course of his career, Brendan Nelson has completed a wide
variety of audit, regulatory and due-diligence engagements. He played
a significant role in the development of the profession’s approach to
the audit of banks in the UK with particular emphasis on establishing
auditing standards. He continues to contribute in his role as a member
of the Financial Reporting Review Panel.

This wide experience makes him ideally suited to chair the audit
committee and to act as its financial expert and he brings related input
from his role as the chair of the audit committee of a major bank. His
specialism in the financial services industry allows him to contribute
insight into the challenges faced by global businesses by regulatory
frameworks.

Paula Rosput Reynolds
Independent non-executive director

Tenure
Appointed 14 May 2015

Board and committee activities
Member of the audit and chairman’s committees

Outside interests
• Non-executive director of BAE Systems Ltd
• Non-executive director of TransCanada Corporation
• Non-executive director of CBRE Group

Age 60 Nationality American

Career
Paula Rosput Reynolds is the former chairman, president and chief
executive officer of Safeco Corporation, a Fortune 500 property and
casualty insurance company that was acquired by Liberty Mutual
Insurance Group in 2008. She also served as Vice Chair and Chief
Restructuring Officer for American International Group (AIG) for a
period after the US government became the financial sponsor from
2008 to 2009.

Previously, Paula was an executive in the energy industry. She was
chairman, president and chief executive officer of AGL Resources Inc.,
an operator of natural gas infrastructure in the US, now a subsidiary of
Southern Company. Prior to this, she led a subsidiary of Duke Energy
Corporation that was a merchant operator of electricity generation.
She commenced her energy career at PG&E Corp.

Paula was awarded the National Association of Corporate Directors (US)
Lifetime Achievement Award in 2014.

Relevant skills and experience
Paula Rosput Reynolds has had a long career leading global companies
in the energy and financial sectors. Her financial background makes her
ideally suited to serve on the audit committee.

Her experience with international and US companies, including several
restructuring processes and mergers, gives her insight into strategic and
regulatory issues, which is an asset to the board.

BP Annual Report and Form 20-F 2016 Sir John Sawers
Independent non-executive director

Tenure
Appointed 14 May 2015

Board and committee activities
Chair of the geopolitical committee; member of the safety, ethics and
environment assurance, nomination and chairman’s committees

Outside interests
• Chairman and partner of Macro Advisory Partners LLP
• Visiting professor at King’s College London
• Governor of the Ditchley Foundation

Age 61 Nationality British

Career
John Sawers spent 36 years in public service in the UK working on
foreign policy, international security and intelligence.

John was Chief of the Secret Intelligence Service, MI6, from 2009 to
2014, a period of international upheaval and growing security threats
as well as closer public scrutiny of the intelligence agencies. Prior to
that, the bulk of his career was in diplomacy, representing the British
government around the world and leading negotiations at the UN, in
the European Union and in the G8. He was the UK ambassador to the
United Nations (2007-09), political director and main board member
of the Foreign Office (2003-07), special representative in Iraq (2003),
ambassador to Egypt (2001-03) and foreign policy advisor to the Prime
Minister (1999-2001). Earlier in his career, he was posted to Washington,
South Africa, Syria and Yemen.

John is now chairman of Macro Advisory Partners, a firm that advises
clients on the intersection of policy, politics and markets.

Relevant skills and experience
Sir John Sawers’ deep experience of international political and
commercial matters is an asset to the board in navigating the complex
issues faced by a modern global company. Sir John brings a unique
perspective and broad experience which makes him ideal to lead the
geopolitical committee. His knowledge and skills related to analysing
and negotiating on a worldwide basis are invaluable to both the board
and the SEEAC.

Andrew Shilston
Independent non-executive director

Tenure
Appointed 1 January 2012

Board and committee activities
Senior independent director and member of the audit, remuneration,
geopolitical, nomination and chairman’s committees

Outside interests
• Chairman of Morgan Advanced Materials plc
• Non-executive director of Circle Holdings plc

Age 61 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. In 2003, after the sale of Enterprise Oil to Shell in 2002,
he became finance director of Rolls-Royce plc until his retirement in
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 is a highly knowledgeable director with wide
experience in the oil and gas, energy and engineering industries.
He has held several positions as a chief financial officer from
which he brings detailed knowledge and skills to the audit and
remuneration committees.

His deep understanding of commercial issues has assisted the board
in its work in overseeing the group’s strategy and his global expertise
across several sectors is an asset to the geopolitical committee.

As senior independent director he oversaw the evaluation of the
chairman.

David Jackson
Company secretary

Tenure
Appointed 2003

David Jackson, a solicitor, is a director of BP Pension Trustees Limited.

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The ages of the board are
correct as at 6 April 2017.

Corporate governanceBP Annual Report and Form 20-F 2016
Executive team
As at 6 April 2017

Tufan Erginbilgic
Chief executive, Downstream

Executive team tenure
Appointed 1 October 2014

Outside interests
• Independent non-executive

director of GKN plc

• Member of the Turkish-British
Chamber of Commerce &
Industry Board of Directors

Age 57 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
Executive vice president,
safety and operational risk

Executive team tenure
Appointed 1 October 2010

Outside interests
No external appointments

Age 53 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, remediation management and the environment. In this
capacity, he looks after the group-wide operating management system
implementation and capability programmes.

Bob has over 30 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,
accountable for safe and compliant exploration and production
operations and stewardship of resources across all regions.

Andy Hopwood
Executive vice-president,
chief operating ofﬁcer,
strategy and regions, Upstream

Executive team tenure
Appointed 1 November 2010

Outside interests
No external appointments

Age 59 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.

Bernard Looney
Chief executive, Upstream

Executive team tenure
Appointed 1 November 2010

Outside interests
• Fellow of the Royal Academy

of Engineering

• Member of the Stanford

University Graduate School of
Business Advisory Council
• Member of the Society of

Petroleum Engineers Industry
Advisory Council

• Fellow of the Energy Institute

Age 46 Nationality Irish

Career
Bernard Looney is responsible for the Upstream segment which
consists of exploration, development and production.

Bernard joined BP in 1991 as a drilling engineer, working in the North
Sea, Vietnam and the Gulf of Mexico. In 2005 he became senior vice
president for BP Alaska before becoming head of the group chief
executive’s office in 2007.

Prior to this, Bob was chief executive of BP Angola and also held several
management positions in 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 the
deepwater Gulf of Mexico.

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. He became executive vice president,
developments, in October 2010, and in February 2013 became chief
operating officer, production, serving in the role until April 2016.

BP Annual Report and Form 20-F 2016 Lamar McKay
Deputy group chief executive

Executive team tenure
Appointed 16 June 2008

Outside interests
No external appointments

Age 58 Nationality American

Career
Lamar McKay is accountable for group strategy and long-term planning,
safety and operational risk and group technology. In addition to supporting
the group chief executive, he also focuses on various corporate
governance activities including ethics and compliance.

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, responsible for exploration, development and
production, serving in the role until April 2016.

Eric Nitcher
Group general counsel

Executive team tenure
Appointed 1 January 2017

Outside interests
No external appointments

Age 54 Nationality American

Career
Eric Nitcher is responsible for legal matters across the BP group.

Eric began his career in the late 1980s working as a litigation and
regulatory lawyer in Wichita, Kansas. He joined Amoco in 1990 and
over the years has held a wide variety of roles, both within and
outside the US.

In 2000, Eric moved to London to work in the mergers and acquisitions
legal team where he played a key role in the formation of the Russian
joint venture TNK-BP. Eric returned to Houston in 2007 where he
served as special counsel and chief of staff to BP America’s
chairman and president.

Most recently he played a leading role in the settlement of the
Deepwater Horizon government claims and resolution of most of the
remaining private claims being litigated in New Orleans.

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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 53-54) and the senior management listed on
these pages. The ages of the executive team are correct as at 6 April 2017.

Dev Sanyal
Chief executive, alternative
energy and executive vice
president, regions

Executive team tenure
Appointed 1 January 2012

Outside interests
• Independent non-executive
director of Man Group plc

• Member of the Accenture Global

Energy Board

• Member of the Board of

Advisors of the Fletcher School
of Law and Diplomacy

Age 51 Nationality British and Indian

Career
Dev Sanyal is responsible for alternative energy and for the Europe and
Asia regions and functionally for risk management, government and
political affairs, economics and policy.

Dev joined BP in 1989 and has held a variety of international roles in
London, Athens, Istanbul, Vienna and Dubai. He was general manager,
Former Soviet Union and Eastern Europe, prior to being appointed chief
executive, BP Eastern Mediterranean Fuels in 1999.

In November 2003 he was appointed chief executive officer of Air
BP International and in June 2006 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. Until April 2016, Dev was executive vice president,
strategy and regions.

Helmut Schuster
Executive vice president,
group human resources

Executive team tenure
Appointed 1 March 2011

Outside interests
• Non-executive director of Ivoclar

Vivadent AG, Germany
Age 56 Nationality Austrian

Career
Helmut Schuster became group human resources (HR) director
in March 2011. In this role he is accountable for the BP human
resources function.

He completed his post graduate diploma in international relations and his
PhD in economics at the University of Vienna and then began his career
working for Henkel in a marketing capacity. Since joining BP in 1989
Helmut has held a number of leadership roles. He has worked in BP in
the US, UK and continental Europe and within most parts of refining,
marketing, trading and gas and power.

Before taking on his current role, his portfolio of responsibilities as vice
president, HR 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 included businesses
such as petrochemicals, fuels value chains, lubricants and functional
experts across the group. He is also a non-executive director of
BP Europa SE.

Corporate governanceBP Annual Report and Form 20-F 2016
Executive management teams

Upstream

(Pictured from left to right)

James Dupree
Chief operating officer, developments
and technology

Andy Hopwood
Chief operating officer, strategy
and regions

Kerry Dryburgh
Head of human resources

Tony Brock
Head of safety and operational risk

Bernard Looney
Chief executive

(Standing, from left to right)
Murray Auchincloss
Chief financial officer

Nigel Jones
Associate general counsel

Downstream

(Standing, from left to right)

Mike O’Sullivan
Chief financial officer

Mandhir Singh
Chief operating officer, lubricants

Paul Reed
Chief executive officer, integrated supply
and trading (to 31 December 2016)

Rita Grifﬁn
Chief operating officer, petrochemicals

Eva Bishop
Associate general counsel

Alan Haywood
Chief executive officer, integrated supply
and trading (effective 1 January 2017)

Doug Sparkman
Chief operating officer, fuels,
North America

(Seated, from left to right)

Angela Strank
Head of technology

Tufan Erginbilgic
Chief executive

Guy Moeyens
Chief operating officer, fuels, Europe
and Southern Africa

Evelyn Gardiner
Head of human resources

Andy Holmes
Chief operating officer, fuels
ASPAC and Air BP

BP Annual Report and Form 20-F 2016Alternative energy

(Pictured from left to right)

David Anderson
Chief financial officer

Catherine Green
Human resources director

Laura Folse
Chief executive officer, wind

Nick Wayth
Chief development officer

Mario Lindenhayn
Chief executive officer, biofuels

Joan Wales
Head of safety and operational risk

Dev Sanyal
Chief executive

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Functional leaders

(Pictured from left to right)

David Jardine
Group head of audit

Susan Dio
Chief executive officer, shipping

Ashok Pillai
Vice president, group reward

(Pictured from left to right)

Jessica Mitchell
Group head of investor relations

Peter Henshaw
Group head of communications
and external affairs

Dominic Emery
Vice president, group strategic
planning

(Pictured from left to right)

David Eyton
Group head of technology

Richard Hookway
Chief operating officer of global
business services and information
technology and systems

Kate Thomson
Group treasurer

Rahul Saxena
Group ethics and compliance
officer

(Pictured from left to right)

Eric Nitcher
Group general counsel

Jan Lyons
Group head of tax

Robert Lawson
Global head of mergers and
acquisitions

Lucy Knight
Human resources vice president,
corporate business activities and
functions

Corporate governanceBP Annual Report and Form 20-F 2016
Introduction from the chairman

It is vital that we are responsive to
all those with whom we come into
contact through our business.

Carl-Henric Svanberg
Chairman

can make a real difference in their home markets. The
board of BP has for many years seen that its task is to
create long-term value for shareholders. To do this it is
vital that we are responsive to all those with whom we
come into contact through our business. This includes
shareholders, employees, customers and communities
alike.

This is a clear task of all companies and their boards. In
the UK we are pleased to be able to work with the current
government on their recent green paper on corporate
governance reform.

In 2016 the Gulf of Mexico committee met for the
last time. The geopolitical committee, now chaired by
Sir John Sawers, is getting into its stride and has proved
its worth as the political environment has changed in a
number of countries.

It is important that we look to the future and ensure that
how we work and what we discuss at our meetings
is always directed at delivering BP’s strategy and
maximizing performance in all areas.

I am very grateful to Bob, his executive colleagues and
my fellow directors for all the work that they have done
over the year. And we are ready for what the future
brings.

Carl-Henric Svanberg
Chairman

The work of the board was challenging in 2016 as we
had to focus on a number of distinct issues in a changing
global environment. Despite this backdrop, it was a year
however when the board continued to work well.

2015 saw the announcement of our settlement with
a number of significant parties in the aftermath of the
Deepwater Horizon accident. This was finally approved
by the appropriate authorities in March 2016. This was a
significant step that has allowed us to look forward.

Your board spent significant time in 2016 in a series of
briefings to understand the challenges of the transition
to a lower carbon economy. And in February 2017 we
communicated our refreshed strategy to investors. It
defines how we see BP’s business evolving over the
coming years. We are clear that a strong core business
will be vital to our success in playing our part in the lower
carbon transition over the coming years.

The negative vote on remuneration at the 2016 AGM
sent us a clear message. At that meeting Dame Ann and
I said that we would listen and make further proposals for
a new remuneration policy in 2017. Dame Ann and the
remuneration committee have worked hard to ensure
that we fully understand the views of our shareholders.
They have also considered wider remuneration within
BP and recognized the importance of engaging and
retaining top executive talent throughout BP. We are
putting forward the new policy at the 2017 AGM and
believe it reflects a fair and balanced approach. The board
recommends that shareholders approve it.

It has been a lesson for the board and it is important for
all of us that we regain the trust of shareholders and
society. BP has come through many tests in the past
years, and is a company with inner strength and is ready
to continue playing its part in delivering light, heat and
mobility to the societies in which we work.

The role of business in society has become the focus
of attention in many countries, not least the UK. BP
is a global business. We cannot change that; indeed
that is our strength. We believe that we can make a
major contribution in demonstrating how global players

BP Annual Report and Form 20-F 2016

BP governance framework
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.

Owners/shareholders

BP board

Nomination
committee
See page 79

Remuneration
committee
See page 76

Chairman’s
committee
See page 79

SEEAC

See page 74

Geopolitical
committee
See page 78

Audit
committee
See page 69

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Strategy/group risks/annual plan

Group chief executive

Group chief executive’s delegations

Executive management

Resource
commitments
meeting (RCM)

Group people
committee
(GPC)

Group disclosure
committee
(GDC)

Group financial
risk committee
(GFRC)

Group operations
risk committee
(GORC)

Group ethics
and compliance
committee (GECC)

Monitoring,
information
and assurance

• Group audit

• Finance

• Safety and

operational risk

• Group ethics

and compliance

• Business integrity

• External market
and reputation
research

• Independent

auditor

• Independent

adviser

• Independent

advice
(if requested)

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A

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BP board
governance
principles:

• BP goal

• Governance

process

• Delegation

model

• Executive
limitations

Delegation
Delegation of
authority through
policy with
monitoring

Accountability
Assurance through
monitoring and
reporting

Board and committee attendance in 2016

Board

Audit
committee

SEEAC

Joint audit/
SEEAC

Remuneration
committee

Geopolitical
committee

Nomination
committee

Chairman’s
committee

Non-executive directors

Carl-Henric Svanberg+

Nils Andersen

Paul Anderson

Alan Boeckmann+

Frank Bowman

Antony Burgmans

Cynthia Carroll

Ian Davis

Ann Dowling+

Brendan Nelson+

Phuthuma Nhleko

Paula Rosput Reynolds

John Sawers+

Andrew Shilston
Executive directors

Bob Dudley

Brian Gilvary

A = Total number of meetings the director was eligible to attend.
B = Total number of meetings the director did attend.
+ Committee chair.

Cynthia Carroll did not attend the board meeting on 26 May as she had to attend a family event.
Brendan Nelson did not attend the board meeting on 6 December due to a conflict with an
RBS board meeting. Phuthuma Nhleko did not attend the board meeting on 14 April due to
urgent business in South Africa.
Committee meeting attendance is noted in each committee report on pages 69-79.

BP Annual Report and Form 20-F 2016

Board activity in 2016

Role of the board
The board is responsible for the overall conduct of the group’s business.
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
1
long-term strategy and approval
of the annual plan.

Monitoring of BP’s
performance against the
strategy and plan.

Ensuring that the principal risks and
uncertainties to BP are identified and that
systems of risk management and control
are in place.

Board and executive
management
succession.

Strategy

In 2016 the board worked
with the executive team to
understand the potential
evolution of the markets in
which the company operates. It
also considered the implications
of a transition to a low carbon
economy.

At its September meeting
the board spent two days
discussing with the executive
team their proposals for the
strategic direction of the group
in the short, medium and longer
term.

The board discusses progress in
delivering these strategic aims on
a regular basis.

During the year, the board
has monitored the company’s
performance against the annual
plan for 2016 and also set the
terms for the annual plan in 2017.

Risk

The board, either directly or through
its committees, regularly reviews
the processes whereby risks are
identified, evaluated and managed.
Activities include:
• assessing the effectiveness of
the group’s system of internal
control and risk management
• identification and allocation of

risks to the board and
monitoring committees (the
audit, SEEA and geopolitical
committees) for 2016, and
confirmation of the schedule
for oversight.

The board reviewed the BP
Energy Outlook, updated in
January 2017, which looks at
long-term energy trends and
develops projections for world
energy markets over the next
two decades.

Following the approval of the
Consent Decree order by the
US court, the Gulf of Mexico
committee was stood down at
the end of the first quarter of
2016. Updates on the remaining
proceedings are being given
directly to the board or other
committees as appropriate.

Finally, the board has had regular
discussions on the development
of a new remuneration policy.

Group risks reviewed by the board
during 2016 included:
• financial resilience (which

examines how the group is
able to respond to a volatile oil
and gas price environment)
• cybersecurity (with the audit

committee and SEEAC
reviewing elements of
cybersecurity risk in their work
over the year).

These remain unchanged for 2017.

The group risks allocated to the
committees for review over the
year are outlined in the reports of
the committees on pages 69-79.

Further information on BP’s
system of risk management is
outlined in How we manage risk
on page 47. Information about
BP’s system of internal control is
on page 111.

Performance and monitoring

The board reviews financial and
operational performance at each
meeting. It receives regular updates
on the group’s performance for the
year across a range of metrics as
well as the latest view on expected
full-year delivery against external
scorecard measures. Updates are
also given on various components
of value delivery for BP’s business.
Regular reports presented to the
board include:

• Chief executive’s report
• Group performance report
• Group financial outlook
• Effectiveness of investment

review

Succession

The board, in conjunction with
the nomination and chairman’s
committees, reviews succession
plans for executive and non-
executive directors on a regular
basis. The board needs to
ensure that potential candidates
are identified and evaluated as
current directors reach the end
of their recommended term of
office, including in the event
of a director needing to leave
unexpectedly.

The board employs executive
search firms when it concludes
that this is an effective way of
finding suitable candidates.
In 2016 we appointed Russell
Reynolds Associates to assist
in the search for non-executive
directors.

• Nils Andersen joined the board

in October 2016 as a non-
executive director. He is a
member of the audit
committee and the chairman’s
committee.

• Quarterly and full-year results
• Shareholder distributions.

The board reviews the quarterly
and full-year results, including
the shareholder distribution
policy. Both the 2015 and 2016
annual reports were assessed
in terms of the directors’
obligations and appropriate
regulatory requirements.

The board monitors employee
opinion via an annual ’pulse‘
survey which includes
measurement of how the BP
values are incorporated into
daily culture around our global
operations.

• Antony Burgmans and Phuthuma

Nhleko, both non-executive
directors, retired from the board at
the AGM on 14 April 2016.

• Sir John Sawers took the chair
of the geopolitical committee
following Antony Burgmans’
retirement.

• Alan Boeckmann took the

chair of the SEEAC, succeeding
Paul Anderson who served as
chair for four years.
Mr Anderson continues as a
member of the committee.
• Ian Davis joined the geopolitical

committee further to the
departure of Antony Burgmans
and Phuthuma Nhleko.

• At the start of the year, Paul

Anderson and Brendan Nelson
stepped down from the
nomination committee and
Alan Boeckmann and
Sir John Sawers joined.
• Cynthia Carroll and Andrew

Shilston will be standing down
from the board at the 2017
AGM.

• The board is proposing Melody
Meyer for election as a director
at the 2017 AGM.

BP Annual Report and Form 20-F 2016Skills and expertise
In order to carry out its duties on behalf of the shareholders, the board
needs to manage its overall membership and continuously maintain its
knowledge and expertise to benefit the business. It does this through
four activity sets:

Succession planning to
ensure future diversity
and balance

Diversity including skills,
experience, gender, ethnicity
and tenure

Training including
site visits and induction
of new directors

Evaluation

Background and diversity

Director

Background

Oil & gas/
extractives/
energy

Engineering/
technology

Financial
expertise

Safety

Brand/
marketing/
reputation

Regulatory/
government
affairs

Diversity

Female

Non
UK/US

Tenure
(years)

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Nils Andersen

Paul Anderson

Alan Boeckmann

Frank Bowman

Cynthia Carroll

Ian Davis

Ann Dowling

Brendan Nelson

Paula Rosput Reynolds

John Sawers

Andrew Shilston

Carl-Henric Svanberg

Diversity
BP recognizes the importance of diversity, including gender, at the board
and all levels of the group. We are committed to increasing diversity
across our operations and have 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 that 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.

New diversity targets have been suggested by the Hampton-Alexander
review in November 2016, to increase female representation on boards,
executive committees and in the executive team direct reports by 2020.
At the end of 2016, there were three female directors (2015 3, 2014 2)
on our board of 14. Our nomination committee actively considers
diversity in seeking potential candidates for appointment to the board.

Independence
Non-executive directors (NEDs) are expected to be independent
in character and judgement and free from any business or other
relationship that could materially interfere with exercising that
judgement. It is the board’s view that all NEDs, with the exception
of the chairman, are independent.

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 other 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.

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, but instead set a general guide of between 30-40
days per year. The time required of directors may fluctuate depending
on demands of BP business and other events. They are expected to
allocate sufficient time to BP to perform their duties effectively and
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 97).

Neither the chairman nor the senior independent director are employed
as an executive of the group.

BP Annual Report and Form 20-F 2016
Training and induction
To help develop an understanding of BP’s business, the board continues
to build its knowledge through briefings and field visits. In 2016 the
board received training on ethics and compliance and digital innovation.

Activity following prior year audit
An external evaluation was carried out at the end of 2015. Following a
selection process led by the senior independent director, Bvalco was
engaged as the external evaluator.

The evaluation tested key areas of the board’s work including:

• participation in the development of strategy

• succession and composition

• oversight of business performance, risk and governance processes.

The effectiveness of the committees in alleviating the board’s overall
oversight was also tested to establish whether this added value for
the board.

Results of the board evaluation and feedback from these interviews were
discussed by the board at its meeting in January 2016, with the results
of the chairman’s evaluation discussed by the chairman’s committee.

Key conclusions of the evaluation included:

• Ensuring an effective strategy process that focused on the long term

and which acknowledged the important role of the board in this
process.

• Continued focus on succession for the board.

• Building on the collaborative and inclusive environment to try and put
more of the monitoring tasks into the committees to allow more time
for broader discussions at the board.

• Further steps should be taken to ensure that where appropriate all

directors can access information and attend external visits for those
committees of which they were not members.

2016 evaluation
The evaluation was undertaken through a questionnaire facilitated by an
external consultant (Lintstock) and individual interviews between the
chairman and each director. The results of the evaluation and feedback
from the interviews were collectively discussed by the board at its
meeting in February 2017, with the results of the chairman’s evaluation
discussed by the chairman’s committee.

The evaluation concluded that the board felt its work and performance
during the year had been positive. There had been an effective process
to develop a refreshed strategy, and board discussions remained open
and constructive.

Actions arising from the evaluation in 2017 included:

• Focus on implementing the strategy, in particular the opportunities

relating to the transition to a lower carbon economy.

• Continued emphasis on improving operational excellence.

• Further examination of the financial performance of the business, in

particular capital allocation and returns.

• Obtaining a better understanding of the group’s ability to effectively

deliver the strategy, including technology, digital and big data.

• Bringing wider perspectives into the board room and gaining deeper

insight into shareholder views.

NEDs are expected to visit at least one business per year as part of
their learning programme. In 2016 the board visited operations in Baku
and Azerbaijan, and members of the SEEAC and other directors visited
operations in Alaska, Colorado and Belgium.

Newly appointed NEDs follow a structured induction process. This
includes one-to-one meetings with management and the external
auditors and also covers the board committees that they join.

Director induction programme

It was helpful to meet a
wide range of company
executives.

Nils Andersen
Non-executive director

Nils Andersen, appointed in 2016, followed a tailored
induction process, also covering the audit committee
that he joined. The programme of topics included:

Board and governance
• BP’s board governance model,
directors’ duties, interests and
potential conflicts.

Business introduction
• BP’s business
• Upstream (exploration,

development, production,
overview of our operations)

• Downstream (refining,

marketing and lubricants)

• Strategy and planning
• BP’s performance relative

• Safety and operational risk
(S&OR), BP’s operating
management system (OMS)
and environmental
performance

• Research and technology
• Legal.

Audit committee speciﬁc
• Upstream and downstream

finance

• Tax
• Oil and gas reserves

accounting

to its competitors.

• Controls, accounting and

Functional input
• Human resources
• Ethics and compliance

reporting

• External auditors and internal

audit

• Treasury and trading.

Board evaluation
BP undertakes an annual review of the board, its committees and
individual directors. The chairman’s performance is evaluated by
the chairman’s committee and his evaluation is led by the senior
independent director.

The evaluation operates on a three-year cycle, with one externally led
evaluation followed by two subsequent years of internal evaluations
carried out using a questionnaire prepared by an external facilitator.

BP Annual Report and Form 20-F 2016Field visits

Non-executive directors are expected to visit at least one business
per year, as part of their learning programme. In 2016 the board
visited operations in Baku, Azerbaijan, and members of the SEEAC
and other directors visited operations in Alaska, Colorado and
Belgium. The board met local management during each visit, and
after each one, the board or appropriate committee was briefed on
the impressions gained by the directors during the visit.

Lower 48, US
Members of the SEEAC visited operations
in Durango, Colorado in October. The visit
was hosted by leadership of the Lower 48
business and included detailed reviews
of production efficiency, operational
management and safety and risk
mitigation. Members saw the Florida gas
plant and a number of well sites
and a produced water storage and
injection facility.

There was a particular emphasis on the
way in which the Lower 48 business
is promoting safety through digital
information sharing of incidents and
leadership communications.

Geel, Belgium
Members of the SEEAC and other directors
visited the petrochemicals plant in Geel, Belgium
in December. They were shown key areas of the
plant, in particular the paraxylene manufacturing
facility. The visit also involved meetings with
site leadership, and a review of safety-related
incidents and trends. The outreach programme
with the surrounding community was also
discussed and commended.

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Alaska, US
Members of the SEEAC and other directors
visited Anchorage and the North Slope
in August. The visit to the North Slope
included reviews of operations and flow
stations as well as the central gas facility.
They also visited pipelines and other critical
infrastructure. Directors met local business
and political leaders in Anchorage, as well
as local BP leadership and other staff.

second half of 2017. Subsequent installation and
commissioning will take place at the field.

Board members also met with site leadership
and were given a detailed update on the Shah
Deniz Stage 2 project as a whole.

Baku, Azerbaijan
The board visited the fabrication site for Shah
Deniz Stage 2 topsides in Baku in May. Board
members were given a tour of the topsides
for the Shah Deniz Bravo production platform
and the quarters and utilities platform. They
reviewed progress of construction and
discussed the safety record at the site – in
particular the fact that more than 17 million
safe man hours had been worked. They
were informed that almost 90% of the
workforce is Azerbaijani. The jackets for the
platform are being constructed separately in
Azerbaijan – with a projected sail away in the

BP Annual Report and Form 20-F 2016
Shareholder engagement

Institutional investors
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 meet with shareholders each year. In 2016 there was an
enhanced programme of engagement by the chairman and the chair of
the remuneration committee following the AGM. This is detailed in the
remuneration committee report on page 76.

Senior management regularly meets with institutional investors
through roadshows, group and one-to-one meetings, events for
socially responsible investors (SRIs) and oil and gas sector conferences
throughout the year.

In March the chairman and all board committee chairs held an annual
investor event. This meeting enabled BP’s largest shareholders to hear
about the work of the board and its committees and for NEDs to engage
with investors.

The chairman and members of the executive team met with SRIs as
part of BP’s annual SRI meeting in November. The meeting examined
a number of operational and strategic issues, including how the board
looks at risk and strategy, the group’s approach to operational risk,
context for the sector and BP in terms of oil price and energy supply and
demand, operating and energy performance in the Upstream, and BP’s
response to the shareholder resolution.

See bp.com/investors for investor and strategy presentations, including
the group’s financial results and information on the work of the board
and its committees.

Private investors
BP held a further event for private investors in conjunction with the UK
Shareholders’ Association (UKSA) in 2016. 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 and performance.

Shareholder engagement cycle 2016

• BP Energy Outlook presentation

• Fourth quarter results

• Investor roadshows with the group chief

executive and chief financial officer

• Chairman and board committee chairs meeting

• UKSA private shareholders’ meeting

• Institutional Investors Group on Climate

Change (IIGCC) meeting

• SRI roadshow following the launch of the BP
Sustainability Report 2015, continuing into Q2

• Annual general meeting

• First quarter results

• Meetings with members of the Church

Investors Group and Charities Responsible
Investment Network

• Upstream field trip to Baku, Azerbaijan

• BP Statistical Review of World Energy launch

• IIGCC meeting

• Second quarter results

• Investor roadshows with the group

chief executive

• Third quarter results

• SRI annual meeting

• IIGCC meeting

More information

Engagement on remuneration continued
throughout the year
See pages 76 and 80.

AGM
Voting levels increased slightly in 2016 to 64.28% (of issued share
capital, including votes cast as withheld), compared to 62.28% in 2015
and 63.13% in 2014. All resolutions were passed at the meeting with the
exception of the non-binding vote to receive the directors’ remuneration
report. Each year the board receives a report after the AGM giving a
breakdown of the votes and investor feedback on their voting decisions
to inform the board on any issues arising.

UK Corporate Governance Code compliance
BP complied throughout 2016 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. Our letters of appointment set a general guide of a time
commitment between 30-40 days per year. 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.

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 meets once or twice a year and between
meetings IAB members remain available to provide advice and counsel
when needed.

The IAB is chaired by BP’s previous chairman, Peter Sutherland. Its
membership in 2016 comprised 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 in 2016 included the global economy and in particular the
effects of Brexit on the rest of the world, developments in political and
economic reform in China, the political situation in Latin America and
Turkey and the 2016 US election.

BP Annual Report and Form 20-F 2016Committee reports

Audit committee

The committee has focused on the financial
performance of the group in a challenging
external environment over the year.

Chairman’s introduction
The committee has focused on the financial performance of the group
in a challenging external environment over the year. Issues considered
included the impact of weak commodity prices on oil and gas
accounting judgements and asset carrying values and how changes in
key long-term price assumptions impacted investment appraisals.

A significant activity of the committee in 2016 was the tender of the
external audit. I believe the tender process was thorough, open and
transparent and I was pleased that the governance arrangements put in
place enabled the committee to make a decision based on high quality
proposals put forward by all the firms involved. Subject to approval by
shareholders, we look forward to working with Deloitte as our new
auditor from 2018. We thank EY for their strong professional standards
and all they have done to provide assurance to the board during their
time as BP’s auditor.

Phuthuma Nhleko retired from the committee in April 2016. He brought
thoughtfulness and challenge to the debate in the committee and I thank
him for his contribution during his tenure. I welcome Nils Andersen who
joined the committee in October 2016 and has commercial experience
from a career in energy, shipping and consumer goods. I believe that
the deep and varied experience of the committee members gives
perspective and insight to our discussions with management.

Brendan Nelson
Committee chair

Role of the committee
The committee monitors the effectiveness of the group’s financial
reporting, systems of internal control and risk management and the
integrity of the group’s external and internal audit processes.

Key responsibilities
• Monitoring and obtaining assurance that the management or

mitigation of financial risks is 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.

• Reviewing financial statements and other financial disclosures and
monitoring compliance with relevant legal and listing requirements.

• Reviewing the effectiveness of the group audit function, BP’s internal
financial controls and systems of internal control and risk management.

• Overseeing the appointment, remuneration, independence and
performance of the external auditor and the integrity of the audit
process as a whole, including the engagement of the external auditor
to supply non-audit services to BP.

• Reviewing the systems in place to enable those who work for BP to
raise concerns about possible improprieties in financial reporting or
other issues and for those matters to be investigated.

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Members

Brendan Nelson

Nils Andersen

Phuthuma Nhleko

Paula Reynolds

Andrew Shilston

Member since November
2010; chair since April 2011

Member since October 2016

Member from February 2011 to
April 2016

Member since May 2015

Member since February 2012

Brendan Nelson is chair of the audit committee. He was formerly
vice chairman of KPMG and president of the Institute of Chartered
Accountants of Scotland. Currently he is chairman of the group audit
committee of The Royal Bank of Scotland Group plc and a member
of the Financial Reporting Review Panel. 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
and competence in accounting and auditing as required by the FCA’s
Corporate Governance Rules in DTR7. 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, as well as competence in the oil and gas sector. 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 and attendance
There were 14 committee meetings in 2016, of which five were carried
out by teleconference. All directors attended every meeting during the
period in which they were committee members.

Regular attendees at the committee meetings include the chief financial
officer, group controller, chief accounting officer, group head of audit and
external auditor.

BP Annual Report and Form 20-F 2016
proposals, the cost of capital and
its application as a discount rate to
evaluate long-term BP business
projects, liquidity (including
credit rating, hedging, long-term
commercial commitments and
credit risk) and the effectiveness
and efficiency of the capital
investment into major projects .

The committee examined the
group’s information technology

risks and financial group risks,
including taxation matters and
the group’s process to assess,
mitigate and monitor them.

BP’s principal risks are listed on
page 49.

For 2017, the board has agreed
that the committee will continue
to monitor the same four group
risks as for 2016.

Other reviews

Other reviews undertaken during
2016 by the committee included:

• Upstream: including financial
performance, strategy and
how the Upstream finance
function supports the
segment.

• Other businesses and

corporate: including the various
business and functional
activities which constitute
‘Other businesses and
corporate’ and how the group
finance organization supports
these activities and the broad
framework of financial control.

• Procurement: including BP’s

procurement spend profile, key
risks and controls.

• Asset carrying values: insight
into the group’s approach to
reviewing asset carrying values
for financial reporting
purposes, particularly in the
Upstream segment – including
IFRS requirements and BP’s
policies.

• Financial metrics proposed for
BP’s new remuneration policy:
consideration of potential
financial metrics for inclusion in
the annual bonus and
long-term incentive plan
elements of the new policy.

Internal control and risk management

During the year the committee
received quarterly reports on
the findings of group audit. It
reviewed the scope, activity
and effectiveness of the
group audit function, with a
focus on how changes in the
organizational structure had been
implemented. In addition, the

committee met privately with
the group head of audit and key
members of his leadership team.

The audit committee also held
private meetings with the group
ethics and compliance officer
during the year.

Training
The committee held learning events on the Modern Slavery Act and
global trends in corporate fraud. It received technical updates from the
chief accounting officer on developments in financial reporting and
accounting policy, including IFRS 16, the new lease accounting standard.

Activities during the year

Financial disclosure

The committee reviewed the
quarterly, half-year and annual
financial statements with
management, focusing on:

• Integrity and clarity of

disclosure.

• Compliance with relevant legal

and financial reporting
standards.

• Application of critical

accounting policies and
judgements.

The committee considered the
BP Annual Report and Form 20-F
2016 and was delegated by the
board to undertake final review
and sign off of the document.
The audit committee reviewed
whether the Annual Report was
fair, balanced and understandable

Risk reviews

The principal risks allocated to the
audit committee for monitoring in
2016 included those associated
with:

Trading activities: including
risks arising from shortcomings
or failures in systems, risk
management methodology,
internal control processes or
employees.

In reviewing this risk, the
committee focused on
developments in the external
market and how BP’s trading
function had responded – including
new areas of activity and impacts
on the control environment. The
committee further considered
updates in the trading function’s
risk management programme,
including compliance with
regulatory developments.

Compliance with applicable
laws and regulations: including
ethical misconduct or breaches of
applicable laws or regulations that
could damage BP’s reputation,
adversely affect operational
results and/or shareholder value
and potentially affect BP’s licence
to operate.

The committee reviewed
key areas of BP’s ethics and
compliance programme,
including the integration of the

and provided the information
necessary for shareholders to
assess the group’s position
and performance, business
model and strategy. It made a
recommendation to the board
who in turn reviewed the report
as a whole. The board’s review
and conclusions are set out on
page 112.

Other disclosures reviewed
included:

• Oil and gas reserves.
• Pensions and post-retirement

benefits assumptions.

• Viability statement.
• Tax strategy.
• Going concern.
• Risk factors.
• Legal liabilities.

business integrity and ethics
and compliance functions,
development of the anti-bribery
and corruption elements of
the programme, enhanced
policies, tools and training and
strengthening of counterparty risk
measures, including due diligence.

Security threats against BP’s
digital infrastructure: including
inappropriate access to or misuse
of information and systems and
disruption of business activity.

The committee reviewed changes
in the cybersecurity landscape,
including events in the energy,
oil and gas industry and within
BP itself. The review focused
on the improvements made in
managing cyber risk, including the
application of the three lines of
defence model and the committee
examined indicators associated
with risk management and barrier
performance.

Financial resilience: including
the risk associated with external
market conditions, supply and
demand and prices achieved for
BP’s products which could impact
financial performance.

The committee reviewed the key
price assumptions used by the
group for investment appraisal and
the judgements underlying those

BP Annual Report and Form 20-F 2016Accounting judgements and estimates
During 2016, the committee was briefed on a quarterly basis on the
group’s key accounting judgements and estimates and was also

briefed in detail on various items during the course of the year. Areas of
significant judgement considered by the committee during the year and
how these were addressed included:

Key issues/judgements in financial reporting

Audit committee review and conclusions

Oil and natural gas accounting

BP uses judgement and estimations when accounting
for oil and gas exploration, appraisal and development
expenditure and in determining the group’s estimated oil
and gas reserves.

The committee reviewed judgemental aspects of oil and gas accounting such as
intangible asset balances relating to exploration and appraisal activities and exploration
write-offs as part of the company’s quarterly due-diligence process. The committee was
also briefed on the year-end reserves process including governance and control activities.

Recoverability of asset carrying values

Determination as to whether and how much an asset
is impaired involves management judgement and
estimates on uncertain matters such as future pricing
or discount rates. Judgements are also required in
assessing the recoverability of overdue receivables and
deciding whether a provision is required.

The committee reviewed the discount rates for impairment testing as part of its annual
process and examined the assumptions for future oil and gas prices and refining margins.
The committee was briefed by management on any changes made to key assumptions
during the year. The majority of the Upstream segment’s tangible assets were tested for
impairment in 2016 and the group recorded a net impairment reversal of $1.9 billion for
the year.

The group’s long-term price assumptions for Brent
National Balancing Point
impairment testing was also reduced.

gas were all reduced in 2016 and the discount rate used for

oil, Henry Hub gas and UK

Accounting for interests in other entities

BP exercises judgement when assessing the level of
control it has as a result of its interests in other entities
and when determining the fair value of assets acquired
and liabilities assumed.

The committee monitored the position on any material overdue receivables and any
associated provisions.

The committee reviewed the judgement on whether the group has significant
influence over Rosneft. The committee received reports from management and the
external auditor which assessed the extent of significant influence, including BP’s
participation in decision making through the election of two BP directors to the Rosneft
board and ongoing work on significant transactions and projects.

The committee was briefed on the accounting for transactions during the year
including the dissolution of the joint operation with Rosneft and the disposal of BP’s
Norwegian upstream business in exchange for an interest in Aker BP.

Derivative ﬁnancial instruments

BP uses judgement when estimating the fair value of some
derivative instruments in cases where there is an absence
of liquid market pricing information – for example, relating to
integrated supply and trading (IST) activities.

The committee received a briefing on the group’s trading risks including the
valuation of derivative instruments using models where observable market pricing
is not available. The committee also visited the BP trading floor in London and
received detailed presentations on the prevention of erroneous or fraudulent
trades, carbon trading and BP‘s oil trading activities.

Provisions and contingencies

BP’s most significant provisions relate to
decommissioning, the Gulf of Mexico oil spill,
environmental remediation, litigation and tax.

Provisioning for, and the disclosure of contingent liabilities relating to the Gulf of
Mexico oil spill was discussed with the committee each quarter as part of the review
of the Stock Exchange Announcement.

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
BP in relation to settlement dates, technology and legal
requirements, among other factors.

The committee discussed the provisions established in the second quarter as a
result of the judgement that a reliable estimate could be made for all remaining
material liabilities arising from the Gulf of Mexico oil spill. Revisions to existing
provisions were also reviewed by the committee.

The committee received briefings on the group’s decommissioning, environmental
remediation and litigation provisioning, including key assumptions used, the
governance framework applied (covering accountabilities and controls), discount
rates and the movement in provisions over time.

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 are underpinned by
management judgement.

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 and was briefed on any material changes to deferred
tax asset recognition.

See Glossary.

Corporate governanceBP Annual Report and Form 20-F 2016Auditor appointment and independence
The committee considers the reappointment of the external auditor
each year before making a recommendation to the board. The
committee assesses the independence of the external auditor on an
ongoing basis and the external auditor is required to rotate the lead audit
partner every five years and other senior audit staff every seven years.
The current lead partner has been in place since the start of 2013. No
partners or senior staff associated with the BP audit may transfer to the
group.

Non-audit services
The audit committee is responsible for BP’s policy on non-audit
services and the approval of 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), UK Auditing
Practices Board (APB) and the UK Financial Reporting Council (FRC).

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.

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. The categories of permitted and
pre-approved services are outlined in Principal accountants’ fees and
services on page 268.

In response to the revised regulatory guidelines of the FRC, the
committee reviewed and updated its policies with effect from 1 January
2017. Changes included:

• Adoption of the FRC’s prohibited non-audit services list.

• Prohibition of all non-audit tax services by the audit firm from 2017

onwards.

• Reduction of the pre-approval requirements for non-audit services in
line with FRC guidance on how ’non-trivial‘ engagements with the
audit firm should be pre-approved by the audit committee.

External audit
Audit risk
The external auditor set out its audit strategy, identifying key risks to be
monitored during the year. These included:

• Determining the liabilities, contingent liabilities and disclosures arising

from the Gulf of Mexico oil spill.

• Estimating oil and gas reserves and resources which has significant

impact on the financial statements, particularly impairment testing and
the calculation of depreciation, depletion and amortization.

• Monitoring for unauthorized trading activity within the trading function

and its potential impact on the group’s results.

• The potential of the macroeconomic environment to materially impact

the carrying value of the group‘s upstream non-current assets.

The committee received updates during the year on the audit process,
including how the auditor had challenged the group’s assumptions on
these issues.

Audit fees
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 $47 million (2015 $51 million), of which 4%
was for non-audit assurance work (see Financial statements – Note 35).
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. Non-audit or non-audit related assurance
fees were $2 million (2015 $3 million). The $1-million reduction in
non-audit fees relates primarily to a reduction in the amount of fees
for other assurance services and services relating to corporate finance
transactions. Non-audit or non-audit related services consisted of tax
compliance services and other assurance services.

Audit effectiveness
The effectiveness of the audit process was evaluated through separate
surveys for the committee members and those BP personnel impacted
by the audit, including chief financial officers, controllers, finance
managers and individuals responsible for accounting policy and internal
controls over financial reporting. The surveys used a set of criteria to
measure the auditor’s performance against the quality commitment set
out in their annual audit plan, including:

• Robustness of the audit process.

• Independence and objectivity.

• Quality of delivery.

• Quality of people and service.

• Value added advice.

Overall the 2016 evaluation concluded that the external auditor
performance had either improved or remained largely constant in key
areas compared to the previous year. Areas with high scores included
quality of delivery of the audit and technical knowledge and expertise.

A key area of focus from 2015 regarded liaison between BP’s own audit
function and the external auditors. Actions taken over the year resulted
in an improvement in scoring for the 2016 survey. Results of the annual
assessment exercise were discussed with the external auditor who
considered these themes for the 2016 audit service approach.

The committee held private meetings with the external auditor during
the year and the committee chair met separately with the external
auditor and group head of audit before each meeting.

BP Annual Report and Form 20-F 2016Audit tendering
The audit committee announced its intention to launch a competitive
audit tender process in BP’s 2013 annual report. The tender process
took place in 2016, with a view to appointing a new external auditor for
the 2018 financial year.

The new audit appointment will be with effect from 2018 to facilitate an
orderly and thorough handover from the existing auditor and to ensure
that the new auditor meets all relevant independence criteria before the
commencement of the appointment.

Governance
The audit committee was responsible for the operation of the audit
tender process, for making a report on the evaluation of the proposals
received during the tender process to BP’s board and for recommending
two firms of auditors to the board together with the audit committee’s
preference between those two firms and its reasons for that preference.

Evaluation
Prior to the RFP being formally launched, briefing meetings were held
with each firm covering key BP segments, functions and geographies;
in addition the audit committee held introductory meetings with the lead
and senior partners from each firm.

In preparation for the tender, BP sought assurance that each firm
would be capable of being independent in the time frame required
by applicable law or regulation before being appointed auditor. The
due-diligence activities conducted as part of the tender included a
review of firm independence.

The proposals from the three firms were evaluated by the audit
committee against the following criteria, as well as the combined
performance as a whole:

• Audit quality.

• Business knowledge.

The governance model established by the audit committee to manage
and support the tender constituted three key groups:

• People, behaviours and cultural fit.

Responsibility

Members

• Planning and project management, including transition.

• Innovation and insight.

• Independence.

• Commercial and contractual structure.

Executive advisory panel

• Assess the firms’ proposals.

• Investigate aspects of capability.

• Present a findings report to the

audit committee.

Governance board

• Govern the day-to-day running of

the tender process.

• Oversee the execution of the

tender.

• Ensure the goals set for the

tender by the audit committee
are met.

• Gather information about the

proposals and communicate to
the committee.

Tender project team

• Liaison with the bidding firms.

• Logistical support to the tender.

• Support for executive advisory
panel and governance board.

Chief financial officers of BP’s
business segments and heads
of its financial functions and
group head of audit.

At the request of the audit committee chair, the commercial and
contractual structure elements were assessed separately from the
other aspects of the firms’ proposals. Evaluation of the proposals was
conducted on a ‘fee blind’ basis.

Chaired by the group controller,
with representatives from
internal functions including
indirect procurement, legal,
group control and financial
reporting.

Representatives from the
finance and procurement
functions.

Following completion of the evaluation, the audit committee
recommended two firms to the board for approval, with a stated
preference for Deloitte. The audit committee believe that Deloitte
has a strong team with the skills and experience to provide rigour and
challenge in the audit.

After considering the audit committee’s recommendation, the
board selected Deloitte as BP’s auditor for the financial year ending
31 December 2018 subject to the approval of shareholders at the 2018
annual general meeting.

BP has complied throughout 2016 with the Statutory Audit Services
Order 2014, issued by the Competition and Markets Authority.

Committee evaluation
The audit committee undertakes an annual evaluation of its performance
and effectiveness.

2016 evaluation
For 2016 an internal questionnaire was used to evaluate the work of the
committee. The review concluded that the committee had performed
effectively. Priorities for 2017 include a review of and visit to BP’s global
business service centres, focus on streamlining committee materials
and further scrutiny on risk management when undertaking business or
functional reviews.

In delegating the day-to-day running of the tender process to the
governance board, the audit committee asked that the tender be
designed to implement a robust process to enable the selection of an
auditor that would be the best fit for the role of external auditor based
on the evaluation criteria agreed by the audit committee and provide the
appropriate level of assurance to BP’s shareholders.

Assessment criteria
An assessment was undertaken to identify which firms would be
reasonably likely to be capable of performing the audit and invited to
participate in the tender; this assessment considered:

• Sector experience.

• Size and geographical presence.

• Extent and nature of existing non-audit services work with BP.

Based on this assessment, three firms were shortlisted to receive the
formal tender request for proposal (RFP). EY, BP’s existing auditor was
not invited to participate due to the legal requirement for BP to rotate its
auditor by 2020.

Corporate governanceBP Annual Report and Form 20-F 2016Role 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 monitoring the management of personal and process
safety and receiving assurance that processes to identify and mitigate
such non-financial risks are appropriate in their 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 function,
group audit, group ethics and compliance, business integrity and group
security. The SEEAC can access any other independent advice and
counsel it requires on an unrestricted basis.

The SEEAC and audit committee worked together, through their chairs
and secretaries, to ensure that agendas did not overlap or omit coverage
of any key risks during the year.

Members

Alan Boeckmann

Paul Anderson

Frank Bowman

Cynthia Carroll

Ann Dowling

John Sawers

Member since September 2014
and chair since May 2016

Member since February 2010

Member since November 2010

Member since June 2007

Member since February 2012

Member since July 2015

Meetings and attendance
There were six committee meetings in 2016. All directors attended
every meeting for which they were eligible, with the exception
of Cynthia Carroll who did not attend the committee meeting on
14 December due to a conflicting external board meeting.

In addition to the committee members, all SEEAC meetings were
attended by the group chief executive, the executive vice president
for safety and operational risk (S&OR) and the head of group audit
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. The group general counsel and group ethics
and compliance officer also attended some of the meetings. At
the conclusion of each meeting the committee scheduled private
sessions for the committee members only, without the presence of
executive management, to discuss any issues arising and the quality
of the meeting.

Safety, ethics and environment
assurance committee (SEEAC)

The SEEAC has continued to monitor
closely and provide constructive challenge
to management in the drive for safe and
reliable operations at all times.

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 individual reports on
the company’s management of highest priority group risks in marine,
wells, pipelines, explosion or release at our facilities, and major security
incidents. The committee also undertook a number of field visits (see
page 67) as well as maintaining its schedule of regular meetings with
executive management.

A particular highlight was confirmation in January that all 26 of the Bly
Report recommendations had been completed across the global wells
organization (GWO). At the same time, we received the final report from
Carl Sandlin, the independent expert we engaged in Upstream, in which
he reported to the committee that such completion had occurred. Carl
had provided valuable insights and advice to the GWO around safety in
wells and process safety more generally, and we were grateful to him
for his work.

Paul Anderson stepped down as chair of the committee in May, having
been the chair since 2012. I am grateful for the opportunity to chair the
committee and we all wish to thank Paul for his service.

Alan Boeckmann
Committee chair

BP Annual Report and Form 20-F 2016Activities during the year

System of internal control and risk management

The review of operational risk and
performance forms a large part of
the committee’s agenda.

Group audit provided reports
on their assurance work on the
system to inform the review.

The committee also received
regular reports from the group
chief executive on operational
risk, and 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.
The committee also received
quarterly reports from group

audit. In addition, the group
ethics and compliance officer
met in private with the chairman
and other members of the
committee over the course of
the year.

During the year the committee
received separate reports on
the company’s management of
risks in:

• Marine
• Wells
• Pipelines
• Explosion or release

at our facilities

• Major security incidents
• Cybersecurity (process control

networks).

The committee reviewed these
risks and their management and
mitigation in depth with relevant
executive management.

Independent expert – Upstream

Mr Carl Sandlin completed his
role as an independent expert
in providing oversight regarding
the implementation of the Bly
Report recommendations.
In January 2016, he reported

to the committee that all 26
recommendations in the Bly
Report had been completed by
the end of 2015. We thank him
for his work with the committee
since 2012.

Field trips

In August the committee (and
other directors) visited Alaska.
The visit encompassed both the
Anchorage office and a trip to
review operations on the North
Slope. In November they visited
operations of the US Lower 48
business in Durango, Colorado.
In December they visited the
Geel petrochemicals facility in
Belgium. In all cases, the visiting
committee members and other
directors received briefings

Corporate reporting

The committee is responsible
for the overview of the
BP Sustainability Report 2016.

on operations, the status of
conformance with the operating
management system (OMS),
key business and operational
risks and risk management and
mitigation. Committee members
then reported back in detail about
each visit to the committee and
subsequently to the board. See
page 67 for further details.

The committee reviewed content
and presentation, and worked
with the external auditor with
respect to their assurance of
the report.

Committee evaluation
For its 2016 evaluation, the committee examined its performance
and effectiveness through a questionnaire and interviews by
external facilitators. Topics covered included the balance of skills
and experience among its members, the quality and timeliness of
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 continued to be generally positive. Committee
members considered that they continued to possess the right
mix of skills and background, had an appropriate level of support
and received open and transparent briefings from management.
All committee members emphasized that field trips remained
an important element of its work, particularly because they
gave committee members the opportunity to examine how risk
management is being embedded in businesses and facilities,
including management culture. Joint meetings between the
committee and the audit committee were considered important in
reviewing and gaining assurance around financial and operational risks
where there was overlap between the committees, particularly in
relation to ethics and compliance (see below).

Joint meetings of the audit and safety, ethics and
environment assurance committees
During the year it was decided to hold standalone joint meetings
of the audit committee and SEEAC on a quarterly basis in order
to simplify reporting of key issues which were within the remit of
both committees and make more effective use of the committees’
time. Each committee retains full discretion to require a further
presentation and discussion on any joint meeting topic at their
respective meeting if deemed appropriate.

The committees jointly met four times during 2016, with
chairmanship of the meetings alternating between the chairman of
the audit committee and the chairman of the SEEAC.

At these meetings the committee reviewed ethics and compliance
and business integrity reports (including significant investigations
and allegations), together with the annual ethics certification and
the 2017 forward programmes for the group audit and ethics and
compliance functions.

See Glossary.

Corporate governanceBP Annual Report and Form 20-F 2016Remuneration committee

After a comprehensive review of our
directors’ remuneration and extensive
shareholder engagement, we are
presenting a clearer, simpler policy for
shareholder approval.

Chair’s introduction
I am pleased to report on the work of the committee in 2016. This
has been a challenging year following the loss of the vote on our
remuneration report at the 2016 AGM. Since then our work has focused
on engaging with shareholders, reflecting on their views, developing
a new remuneration policy for the board, and on determining pay
outcomes for 2016. Proposals for our new policy are set out in the
Directors‘ remuneration report on pages 101-110. The policy will be put
forward for approval by shareholders at the 2017 AGM.

The committee’s membership and detailed activities over the year are
contained in this part of the annual report.

Professor Dame Ann Dowling
Committee chair

Role of the committee
The role of the committee is to determine and recommend to the board
the remuneration policy for the chairman and executive directors. In
determining the policy the committee takes into account various factors,
including structuring the policy to promote the long-term success of the
company and linking reward and business performance.

Key responsibilities
The committee undertakes its tasks in accordance with applicable
regulations, including those made from time to time under the
Companies Act 2006, the UK Corporate Governance Code and the
UK Listing Authority’s Listing Rules in relation to the remuneration of
directors of quoted companies.

• Determine the policy for the chairman and the executive directors (the

policy) for inclusion in the remuneration policy for all directors.

• Review and determine the terms of engagement, remuneration and

termination of employment of the chairman and the executive
directors as appropriate and in accordance with the policy, and be
responsible for compliance with all remuneration issues relating to the
chairman and the executive directors.

BP Annual Report and Form 20-F 2016

• Prepare the annual report to shareholders to show how the policy has

been implemented, so far as it relates to the chairman and the
executive directors.

• Approve the principles of any equity plan that requires shareholder

approval.

• Approve the terms of the remuneration (including pension and

termination arrangements) of the executive team as proposed by the
group chief executive.

• Approve changes to the design of remuneration, as proposed by the

group chief executive, for the group leaders of the company.

• Monitor implementation of remuneration for group leaders to ensure

alignment and proportionality.

• Engage such independent consultants or other advisers as the

committee may from time to time deem necessary, at the expense of
the company.

Members

Ann Dowling

Alan Boeckmann

Antony Burgmans

Ian Davis

Member since July 2012 and
chair since May 2015

Member since May 2015

Member from May 2009 to
April 2016 and chair from
May 2011 to May 2015

Member since July 2010

Andrew Shilston

Member since May 2015

Antony Burgmans stood down from the committee upon his retirement
from the board in April 2016.

Carl-Henric Svanberg and Bob Dudley attend meetings of the
committee except for matters relating to their own remuneration.
Bob Dudley is consulted on the remuneration of other executive
directors and the executive team. Both executive directors are consulted
on matters relating to the group’s performance.

The group human resources director normally attends meetings and
other executives may attend where necessary. The committee consults
other board committees on the group’s performance and on issues
relating to the exercise of judgement or discretion.

Meetings and attendance
The committee met 11 times during the year; twice before the AGM
and on nine occasions since. All directors attended each meeting that
they were eligible to attend, either in person or by telephone, with the
following exceptions:

• Antony Burgmans did not attend the meeting on 17 March due to a

conflict with an external meeting.

• Andrew Shilston did not attend the meeting on 21 June, scheduled at

late notice, due to a prior commitment.

Activities during the year
In the months before the AGM, the committee focused on the
outcomes for 2015. This involved reviewing directors’ salaries and the
group’s performance outcome which in turn determined outcomes for
the annual bonus and the Executive Directors’ Incentive Plan (EDIP).

Following the negative vote on the Directors' remuneration report
(DRR), the chairman and the chair of the remuneration committee
made a commitment at the 2016 AGM to be responsive to shareholder
feedback and to formulate a new policy for 2017.

In all its discussions the committee has focused on the overall quantum
of executive director remuneration and has sought to reflect the views of
shareholders and the broader societal context in its decisions.

Shareholder engagement
There has been substantial engagement with shareholders during the
year. This has been carried out primarily by the chair of the committee,
with additional dialogue by the chairman and the company secretary.
Engagement by the committee chair was aimed at understanding
shareholders’ views on the company’s 2014 policy, testing proposals
and seeking support for the new policy to be put to shareholders at the
2017 AGM. Meetings with proxy voting agencies have also taken place.
In total, the remuneration committee chair has held 68 meetings or calls
with investors and proxy advisers in the period from May 2016 to the
2017 AGM. These meetings were conducted to understand concerns,
test strategic direction and present a refined policy.

Committee evaluation
An internally facilitated evaluation was undertaken in 2016 to examine
the committee’s performance during the year. The evaluation concluded
that the committee had conducted an effective review of a wide range
of options when considering the new policy and was addressing
effectively the balance of commercial and societal constraints.

Focus areas for 2017 included maintaining oversight of stakeholder
and investor views on remuneration, staying up to date with external
developments and best practice, while managing the challenge of the
transition between the 2014 and 2017 remuneration policies.

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For the remainder of 2016 and into early 2017, the committee has
focused on developing a new policy and then determining pay
outcomes for 2016 (the final year of the 2014 policy). It examined the
circumstances around the adverse vote and considered feedback from
the engagement with shareholders.

Committee focus after the AGM
A detailed work plan for the committee was agreed for the year.
The committee chair spoke to a number of the company’s larger
shareholders shortly after the AGM and began a structured shareholder
engagement programme in the UK and US.

The committee decided that a new remuneration adviser should be
appointed to assist with its work. After a competitive tender process
Deloitte was appointed and has been working with the committee since
May 2016.

The committee, over the series of meetings:

• Analysed the structure and operation of remuneration and compared it

with prevailing and emerging best practice.

• Considered a broad range of options in discussion with shareholders

before distilling to two choices for full shareholder consultation.

• Conducted a detailed review of the number, use and combination of
performance measures to assess how they could be simplified while
also supporting the business strategy.

• Considered the quantum of incentives in the context of securing fair

and commercial outcomes relative to senior colleagues.

• Reviewed scenarios to improve alignment of remuneration outcomes

with shareholder interests.

• Conducted a final review of the proposed policy to ensure that it would

continue to promote the company’s long-term business strategy.

The committee has also considered the implications of the transition
from the 2014 to the 2017 policies, in particular relating to share grants
and pension. It also reviewed potential outcomes for 2016 at the end of
the year.

How did we develop the new policy?

Collate feedback

Design and test

Develop proposal

Finalize policy

Implement

Remuneration policy review

Listen

Test outlines

Present developing

proposal

Present final proposal
and seek support at AGM –
17 May 2017

Shareholder dialogue throughout the whole process

Spring 2016

Summer 2016

Autumn/winter 2016

AGM 2017

BP Annual Report and Form 20-F 2016

In 2016 Ian Davis joined the committee, Antony Burgmans and
Phuthuma Nhleko left the committee on retirement from the board, and
Sir John Sawers became the new chair.

Carl-Henric Svanberg and Bob Dudley attend all committee meetings
and the executive vice president, regions and the vice-president,
government and political affairs attend as required.

Meetings and attendance
The committee met three times during the year. All directors attended
each meeting that they were eligible to attend.

Activities during the year
The committee developed the work it had started in 2015 by considering
issues that affect all BP’s key geographies, for example the continuing
low oil price and BP’s investment approach.

The implications of the UK referendum on Brexit and the US presidential
election were discussed at each meeting.

The committee considered the impact of geopolitical events on BP’s
interests in the Middle East and in Egypt, Russia and Turkey.

Committee evaluation
The committee held its first review at the end of 2016, focusing on
its processes and effectiveness. The review was undertaken through
a questionnaire, with the committee discussing the output of the
evaluation in a private session at its February 2017 meeting.

The review concluded that while the committee was still evolving in
terms of coverage and content, it had performed effectively. Areas of
focus for 2017 included gaining greater insight and advice from advisers
with direct political experience and placing emphasis on those regions
and topics that would most impact BP’s business or reputation as a way
of helping to ease time pressure on the committee’s agenda.

Geopolitical committee

Chairman’s introduction
I am pleased to report on the work of the geopolitical committee
in 2016. I thank Antony Burgmans for his work as chair of this
committee in the first part of the year.

Sir John Sawers
Committee chair

Role of the committee
The committee monitors the company’s identification and management
of geopolitical risk.

Key responsibilities
• Monitor the company’s identification and management of major and

correlated geopolitical risk and consider reputational as well as financial
consequences:

– Major geopolitical risks are those brought about by social, economic
or political events that occur in countries where BP has material
investments that can be jeopardized.

– Correlated geopolitical risks are those brought about by social,
economic or political events that occur in countries where BP
may or may not have a presence but that can lead to global
political instability.

• Review the company’s activities in the context of political and

economic developments on a regional basis and advise the board
on these elements in its consideration of BP’s strategy and the
annual plan.

Members

John Sawers

Paul Anderson

Frank Bowman

Antony Burgmans

Cynthia Carroll

Ian Davis

Phuthuma Nhleko

Member since September 2015
and chair since April 2016

Member since September 2015

Chair from September 2015
to April 2016

Member since September 2015

Member since September 2016

Member from September 2015
to April 2016

Andrew Shilston

Member since September 2015

BP Annual Report and Form 20-F 2016Chairman’s and nomination committees

Chairman’s introduction
The chairman‘s and nomination committees have been actively involved
in the evolution of the board and its work in 2016.

Carl-Henric Svanberg
Committees’ chair

Chairman’s committee
Role of the committee
To provide a forum for matters to be discussed among the non-
executive directors.

Key responsibilities
• Evaluate the performance and the effectiveness of the group chief

executive.

• Review the structure and effectiveness of the business organization.

• Review the systems for senior executive development and determine
succession plans for the group chief executive, executive directors and
other senior members of executive management.

• Determine any other matter that is appropriate to be considered by

non-executive directors.

• Opine on any matter referred to it by the chairman of any committees

comprised solely of non-executive directors.

Members
The committee comprises all the non-executive directors. Directors
join the committee immediately on their appointment to the board.
The group chief executive attends meetings of the committee when
requested.

Meetings and attendance
The committee met seven times in 2016. All directors attended every
meeting for which they were eligible, with the exception of Cynthia
Carroll who did not attend the meeting on 26 May as she had to attend a
family event. The chairman did not attend the meeting on 28 January as
it was for his evaluation.

Activities during the year
• Evaluated the performance of the chairman and the group chief

executive.

• Reviewed the evolution of the company’s strategy given anticipated

market conditions over the coming decade and the approach adopted
for the annual plan.

• Assessed the prioritization of investment opportunities.

• Considered succession plans for the senior executive team.

Nomination committee
Role of the committee
The committee ensures an orderly succession of candidates for
directors and the company secretary.

Key responsibilities
• Identify, evaluate and recommend candidates for appointment or

reappointment as directors.

• Identify, evaluate and recommend candidates for appointment as

company secretary.

• Keep the mix of knowledge, skills and experience of the board under

review to ensure the orderly succession of directors.

• Review the outside directorship/commitments of non-executive

directors.

Members

Carl-Henric Svanberg

Member since September 2009
and chair since January 2010

Alan Boeckmann

Member since April 2016

Ann Dowling

Ian Davis

John Sawers

Andrew Shilston

Member since May 2015

Member since August 2010

Member since April 2016

Member since May 2015;
attended meetings previously
as senior independent director

Alan Boeckmann and Sir John Sawers joined the committee in 2016.
Paul Anderson and Brendan Nelson stood down, and Antony Burgmans
left on his retirement from the board.

Meetings and attendance
The committee met five times during the year. All directors attended
each meeting that they were eligible to attend.

Activities during the year
The committee continued to keep the composition and skills of the
board under review.

Cynthia Carroll and Andrew Shilston will be standing down from
the board in 2017 and there will be further retirements in 2018. The
committee focused on maintaining a strong group of current and former
chief executives, while ensuring appropriate diversity in all forms.

The committee appointed Nils Andersen, the former CEO of Maersk,
to the board in October 2016. A search has been initiated for further
candidates with the intent of maintaining the gender diversity on the
board, and as a result the board is proposing Melody Meyer for election
as a director at the 2017 AGM.

The board as a whole considers succession planning and diversity as
discussed on pages 64-65.

Committee evaluation
The evaluation concluded that the committee was generally working
well. It was important to ensure that future work would be focused on
building a board capable of governing the company as it implements its
strategy towards 2021 and beyond. There should be a strong continued
focus on diversity.

Corporate governanceBP Annual Report and Form 20-F 2016Directors’ remuneration report
Letter from the remuneration committee chair

After a thorough review and extensive
shareholder engagement, we believe
the new policy is simpler, transparent
and has strategic focus.

Professor Dame Ann Dowling
Chair of the remuneration committee

Dear shareholder,

Last year’s AGM remuneration vote was a clear
message about how we manage executive pay.
We made a commitment to respond in a constructive
way and have taken a comprehensive look at
remuneration of our executive directors.

We are proposing to make a number of significant
changes to our remuneration policy for 2017 which will
make it simpler, better align pay and performance, and
lead to a reduced maximum award for the group chief
executive (GCE) and the chief financial officer (CFO).

We have held extensive dialogue with many of our
largest shareholders as well as representative bodies
beginning in May 2016 and running through to this
year’s AGM. We have listened and sought to respond
to their concerns. I would like to thank all those who
took part in the process for their time and insight. It is
clear that shareholders and other stakeholders would
like our remuneration policy to be simpler, more
transparent, and to lead to reduced levels of reward.
There is also a wish to see the committee make greater
use of discretion.

BP is a global company with a global management
team, competing for talent in a demanding
environment. The company’s ability to attract and
retain the high-calibre executives required to lead this
complex business is important for shareholders. We
are mindful of this and have tried to balance these
commercial pressures with the wider social context
when determining executive pay.

Although we are still working under our 2014 policy,
we have used some of the principles from our new
policy in making our decisions for pay in 2016. We have
considered the formulaic results and outcomes for
shareholders and then exercised downward discretion
to reach our final decisions.

As a result – in a year of good performance and
progress – Bob Dudley‘s total single figure for 2016 has
been reduced by some 40% compared to last year.

Future remuneration policy
The proposed remuneration policy is designed to
ensure a clear link between delivery of BP’s strategy
and pay.

Over the past year, there has been much debate
in the UK regarding pay models. We appointed new
independent advisers and approached our review
with an open mind. We explored a number of different

Key outcomes for 2016

Bob Dudley – total pay

A year of progress
and performance
for the company.

Total single ﬁgure in
2016 for Bob Dudley is
$11.6 million – 40%
lower than for 2015.

$19.4m

Committee discretion
reduced pay by
$2.2 million.

Maximum opportunity
for 2017 and beyond
signiﬁcantly reduced.

$13.8m

$11.6m

2015

2016
Formulaic
outcome

2016
Outcome after
committee discretion

BP Annual Report and Form 20-F 2016Directors’ remuneration report – overview

remuneration structures before focusing on two
for further consideration – restricted shares and
performance shares. We consulted with shareholders
and the board has reaffirmed its view that performance
shares rather than restricted shares remain the
appropriate structure at the current time as they align
pay outcomes with long-term performance.

Key changes
From 2017, we propose a simplified approach with a
significant reduction in overall remuneration levels.

• We will operate only two incentive plans –
a short-term annual bonus and a long-term
performance share plan.

• The maximum annual bonus will only be earned where
stretch performance is delivered on every measure.

• The level of bonus paid for an ‘on-target’ score will be

reduced by 25%.

• The bonus performance scale for executive directors

will be the same as the wider professional and
managerial employee population.

• The proportion of annual bonus that must be deferred

into shares will be increased from 33% to 50%.

• Deferred shares will no longer be matched with

additional shares.

• The maximum longer-term incentives for the GCE
will be reduced from seven times salary (previously
granted as matching shares on the deferred annual
bonus and performance shares) to a maximum of five
times salary.

Policy features
In addition, the following features of the new policy
support the group’s long-term strategic priorities,
which are in the interests of all stakeholders:

• A simplified performance assessment providing a clear
link between the delivery of BP’s strategy, outcomes
for shareholders and pay.

• An annual bonus that rewards safety, reliable

operations and financial performance during the year
based on the annual plan.

• For long-term performance share awards, performance
will be tested and shares will vest after three years, but
awards will not be released until the end of a further
three-year period – a six-year period in total. This
lengthy period reinforces the executive’s stewardship
of the company.

• Target ranges for total shareholder return (TSR) and
return on average capital employed (ROACE) will be
disclosed at the start of the performance period. For
2017 awards, these determine eighty per cent of the
available performance shares.

• The remainder of the performance shares will be based
on strategic measures, including alignment with the
company’s progress towards a lower carbon transition
over the longer term.

• Where appropriate, the committee will exercise
its discretion in determining outcomes, which
will include a broader consideration of outcomes
for shareholders, safety and environmental
performance.

• Stronger malus and clawback provisions.

• Minimum shareholding requirements of five times

base salary will be maintained, and a significant portion
of the new package will continue to be linked to
performance and delivered in BP shares. It is expected
that Bob Dudley and Dr Brian Gilvary will maintain a
shareholding of at least 250% of salary for two years
following retirement.

How we responded to shareholders in developing our new policy

Simplification

Reduced package
versus 2014 policy

Link to strategy

Stewardship

• Simpler package – fixed

pay, bonus and long-term
shares.

• Removal of matching

shares.

• Maximum opportunity for
long-term incentives has
been significantly reduced
from seven times to five
times salary for the GCE.
• On-target bonus reduced

by 25%.

• Clearer link between

strategy and incentive
targets.

• Review of measures for
bonus and long-term
incentives.

• TSR and ROACE targets
disclosed in advance.

• Five times salary
shareholding
requirements.
• Post-retirement
shareholding.
• Safety and the

environment remain
important
considerations.

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – overview

Performance and pay for 2016
Our full year results were good in the context of
tough conditions; however the board recognizes the
opportunity for further improvement. We have made
considerable progress over the year on a number of the
measures by which we judge our performance. We have
executed our projects safely and more efficiently. We
have driven down costs and made careful judgements
about the best use of capital.

The board has worked with Bob Dudley and the
executive team on BP’s strategic direction. This has
been a significant step forward in defining BP’s pathway
to sustained growth. The year closed with the
announcement of a number of major additions to our
portfolio, all aimed at contributing to returns over both the
short and the longer term.

All of this has been reflected in an improved share price
during the year and good returns for shareholders.

2016 outcomes
We determined executive pay for 2016 and have
exercised downward discretion in coming to our
final decision.

• The annual bonus for 2016 was based on a combination

of safety and value based measures.

• Overall performance has been good; however the

threshold performance for loss of primary containment
(LOPC) was not met, partly due to harsher winter
operating conditions in our unconventional gas
operations in the US.

• The committee exercised discretion and applied some of
the principles of our new policy early. As a result, a bonus
of 81% of maximum based on the previous formulaic
outcome was reduced to 61% of the maximum.

• For performance shares awarded in 2014, vesting will

be determined by a combination of relative TSR,
financial, safety and operational performance assessed
over the three years from 2014 to 2016.

• Again the committee has exercised discretion to
reduce the vesting outcome, which is expected
to be 40% of the maximum award. This discretion
was applied to the operating cash flow element of

the award, reflecting the wider performance of the
business and outcomes for shareholders over
the three-year period.

• A portion of the annual bonuses for 2013 was deferred
and a corresponding matching award made in 2014.
Vesting required satisfactory safety and environmental
sustainability performance over the three years from
2014 to 2016. The committee was satisfied that this
condition had been met and these awards have vested
in full.

• From September 2016 Bob Dudley had no further
service accrual under the defined benefit pension
arrangements.

In a year of good performance and progress, the total
single figure for Bob Dudley in 2016 is $11.6 million, 40%
lower than for 2015.

In addition to the above, the executive directors have
voluntarily agreed the extension of vesting periods for
certain legacy share awards as a transitional approach
to the new policy.

Conclusion
I believe that the board has responded positively to the
events of 2016 and has taken significant action. In this,
we have worked collaboratively with Bob Dudley and
Dr Brian Gilvary.

The committee believes that the decisions on the
2016 outcomes represent a balance between BP’s
performance and shareholder outcomes over the
relevant periods.

I have consulted widely with shareholders and listened
to and sought to act on their concerns, and have been
sensitive to developments in the society in which we
work. We believe that the new policy is simpler,
transparent and has strategic focus.

Professor Dame Ann Dowling
Chair of the remuneration committee
6 April 2017

How did we determine 2016 outcomes?

Assess
performance

Review outcomes
with board
committees

Align with
employees

Apply discretion

• Checked performance

against safety and value
measures.

• Reviewed the measures

against targets set.

• Sought views from the
audit and safety, ethics
and environmental
assurance committees
to ensure a thorough
review of performance.

• Considered outcomes
in relation to BP’s group
leaders and the broader
comparator group of
US and UK employees
in professional and
managerial roles.

• Used judgement to
reflect the broader
market environment
and outcomes for
shareholders.

More information

Single ﬁgure table
Page 90

Annual bonus scorecard
Page 92

2014-2016 performance shares scorecard
Page 93

BP Annual Report and Form 20-F 2016Directors’ remuneration report – overview

Business performance

We have made good progress, with strong share price growth and the announcement of a number of
major investments all aimed at contributing to returns over the short and longer term.

Key strategic highlights

• Six Upstream major project start-ups.
• Deepwater Horizon commitments clarified.
• Biggest Downstream fuels launch in a decade.

Performance outcomes

$17.6bn

Operating cash flow,
excluding Gulf of Mexico
payments.

$7.5bn

Dividends paid,
including scrip.

$7bn

Cash cost reduction
target achieved one
year ahead of plan.

Annual bonus

81%
Formulaic outcome
(% of maximum)

-20%
Committee discretion
to reduce award

61%
Final outcome after
committee discretion
(% of maximum)

Performance shares

57%
Formulaic outcome
(% of maximum)

-17%
Committee discretion
to reduce award

40%
Expected outcome after
committee discretiona
(% of maximum)

Performance measures
(% weighting)

Nil

Maximum

Performance measures
(% weighting)

Nil

Maximum

Value
Operating cash ﬂow (excluding Gulf
of Mexico oil spill payments) (30%)
Underlying replacement cost proﬁt (25%)
Corporate and functional costs (10%)

Major project delivery (5%)

Safety
– Loss of primary containment (10%)

– Tier 1 process safety events (10%)

– Recordable injury frequency (10%)

Financial
Relative TSR (33.3%)

Operating cash ﬂow (excluding Gulf
of Mexico oil spill payments) (33.3%)

Strategic imperatives
Relative reserves replacement
a
ratio (RRR) (11.1%)

Major project delivery (11.1%)

Safety and operational risk
– Loss of primary containment (3.7%)

– Tier 1 process safety events (3.7%)

– Recordable injury frequency (3.7%)

a The final outcome for part of this award is based on the company’s relative RRR ranking, presently
assumed to be third amongst its peers: this will not be known until after the publication of our
peers’ reports and will therefore be reported in the directors’ remuneration report for 2017.

Remuneration outcomes

Bob Dudley, group chief executive
Total remuneration

2016

2015

2014

Dr Brian Gilvary, chief ﬁnancial ofﬁcer
Total remuneration

$11.6m

$19.4m

$16.4m

2016

2015

2014

£4.2m

£5.1m

£3.6m

Overall pay down
40%

Performance pay downb
32%

Overall pay down
18%

Performance pay downb
23%

Salary and benefits

Retirement benefits

Annual bonus

Performance shares

b Bonus and performance shares.

Share ownership

Shareholding is a key means by which the interests of executive directors’ are aligned with those of shareholders.
As at 22 March 2017 both directors had holdings in BP which significantly exceeded their shareholding requirement.
Further details are set out on page 95.

Bob Dudley, group chief executive

Dr Brian Gilvary, chief ﬁnancial ofﬁcer

Policy requirement: minimum of 500% of salary

2,700,516 sharesc

825% of salary

1,543,297 shares

959% of salary

cHeld as ADSs.

BP Annual Report and Form 20-F 2016Corporate governance2016Summary of our pay and performance for 2016
Directors’ remuneration report – overview

Summary of our remuneration policy and approach for 2017

New approach

Simplification.

Reduced package
versus 2014 policy.

Link to strategy.

Stewardship.

Competitive salary and benefits to reflect role
and home country norms

Elements of package

Salary and benefits

Retirement benefits

Annual bonus

Performance shares

Share ownership

Approach

Salary and benefits

Fixed pay policy is unchanged. Salary and benefits are set at a level which reflects the scale and complexity of the
role while recognizing competitive practice in the relevant market.

• The salary for the group chief executive will remain at

$1,854,000 for 2017. Bob Dudley has not received a salary
increase since July 2014.

responsibilities for BP’s trading and shipping functions. This
increase of 3.75% is within the range used by the company for
other UK and US employees.

• With effect from the AGM, the salary for the chief financial officer

• Benefits will remain unchanged – these include

will be £759,000.

• The increase to Dr Brian Gilvary’s salary reflects the changes

made to his role in 2016 when he took on additional

car-related benefits, security assistance, insurance and
medical benefits.

Retirement benefits

• From September 2016, Bob Dudley has no further service

accrual under the defined benefit pension arrangements. The
401(k) benefits have been partially capped for future years.

• Dr Brian Gilvary receives a cash supplement on the same
terms as other participants in the BP UK defined benefit
scheme. He receives no further service accrual under the
defined benefit pension arrangements.

Annual bonus

Up to 225%
of salary

The bonus links variable pay to safety, reliable operations and financial performance for the year.

• Maximum bonus only payable for outperformance on

• Awards will be subject to clawback and malus provisions.

every measure.

• The measures for the bonus are set annually to reflect

• Bonus payable for delivery of bonus scorecard of 1.0 out of

annual priorities.

2.0 reduced by 25% to half of maximum.

• For 2017, performance judged on three key areas:

• 50% of any bonus earned will be paid in cash; there will be a

mandatory deferrral of 50% into shares for three years.

• Removal of bonus share matching arrangements – deferred

– safety (20%)
– reliable operations (30%)
– financial performance (50%).

shares will not accrue any match.

• Overall discretion to review outcomes in the context of annual

performance.

Performance shares

Directly linked to long-term performance and represents the largest part of the package.

GCE – 500%
CFO – 450%
of salary

• Three-year performance period, with further three-year

holding period.

• Measures aligned to long-term strategy and shareholders’

interests.

• Awards will be subject to clawback and malus provisions.

• For 2017 awards, performance judged on three key areas:
– TSR relative to oil and gas majors over three years (50%)

– ROACE in 2019 (30%)
– strategic progress assessed over the performance

period (20%).

• Additional safeguard – broader performance including

absolute TSR performance and safety and environmental
factors to be considered before determining vesting
outcomes.

Share ownership
Share ownership

Stewardship and alignment with shareholders

• Continuing requirement for directors to maintain a holding

• In addition the executive directors have voluntarily agreed

of five times salary.

• It is expected that Bob Dudley and Dr Brian Gilvary will maintain
a holding of at least 250% of salary for two years following
retirement.

to extend the vesting periods of certain legacy share awards
until post retirement.

BP Annual Report and Form 20-F 20162017Long-term shareholdingBonus aligned with annual objectivesShare award for meeting three-year targetsIntroduction

This year the board
has prepared two reports
on remuneration.

First, a report on how directors will be paid in 2017 and
how the 2014 policy has been implemented for 2016.
This will be the subject of an advisory vote at the 2017
AGM.

Second, a report which sets out the proposed 2017
remuneration policy for the three years commencing
at the 2017 AGM. This will be the subject of a binding
vote.

Contents

86
87
90
91
95
101

Features of 2017 policy
Implementation of 2017 policy
Single figure table for 2016
Pay and performance for 2016
Stewardship and regulatory information
2017 proposed policy

BP Annual Report and Form 20-F 2016Corporate governance
Directors’ remuneration report

Features of 2017 policy

The remuneration policy proposed for 2017 is based on
a detailed review of pay and an extensive programme
of shareholder engagement following the 2016 AGM.

As a result, we are proposing some fundamental
changes to simplify the structure and reduce the level
of pay for our 2017 policy onwards.

Clearer link between pay and strategy

BP set out an update of its strategy in February 2017. The foundations for
strong performance are safe and reliable operations, a balanced portfolio
and a focus on returns. Our strategic priorities include:

Shift to gas and
advantaged oil in
the upstream

Venturing and low
carbon across
multiple fronts

Market-led
growth in the
downstream

Modernizing the
whole group

Shareholders have been clear that they wish to see remuneration
measures that are relevant to BP’s strategy and long-term
performance and which are genuinely stretching.

We are putting in place a balanced set of measures to enable a
rounded assessment of performance against our strategy. Weightings
for each of the measures may vary over time.

Annual bonus

Performance shares

Measures reflect safety,
reliable operations and financial
performance over the year.

Measures focus on financial
returns over the longer term
and progress against the
strategic priorities.

The culture of long-term stewardship is reinforced by the requirement for
our senior leadership to own shares in BP over the long term.

Shareholder involvement in the new policy

The new policy reflects the outcome of an intense period of engagement
with shareholders beginning in May 2016 and running through to this
year’s AGM. There has been extensive work by the remuneration
committee and the board. The committee chair has held 68 meetings or
calls and the committee has met 13 times since the 2016 AGM.

The committee has sought to address a number of matters raised during
this engagement.

Simpliﬁcation and transparency
Many shareholders said they found our 2014 policy too complicated.

In response the committee has simplified the structure by removing the
matching share element of the deferred annual bonus. We have also
reduced the number of measures used to determine the vesting of
performance shares and have eliminated any duplication of measures
between annual and long-term plans.

We have simplified the formula used to determine the payment of the
annual bonus. Outperformance on every measure is now required to
achieve maximum payment, aligning executive directors with the wider
professional and managerial employee population.

In addition to this simplification, to improve transparency we will disclose
the threshold and outperformance levels that determine the vesting of up
to eighty per cent of the available performance shares for 2017 at the
beginning of the performance period.

Safety
The 2014 policy used safety measures in all three of its performance
elements: the annual bonus, deferred shares and performance shares.
A number of shareholders considered that this placed too much reward
focus on safety measures.

The new policy retains tier 1 process safety events and recordable injury
frequency as measures for the annual bonus. There are no longer safety
measures for performance shares, however the committee will
incorporate the group’s longer-term safety and environmental performance
as an underpin when evaluating outcomes for performance share awards.
This will include consideration of a number of measures, including LOPC
and input from the safety, ethics and environment assurance committee
(SEEAC) to inform the exercise of the committee’s discretion.

This ensures that BP’s safety performance in the short and long term
remains a significant consideration in remuneration.

Climate change
In 2015 the board supported a shareholder resolution which sought
disclosure around ‘BP’s evolving approach to KPIs and executive
incentives, in the context of the transition to a low carbon economy,
including the role played by the relative reserves replacement ratio (RRR)’.

The committee believes that our new strategic priorities support a lower
carbon future. These include the shift towards gas in our portfolio and the
growth of lower carbon activities – including venturing, renewable trading
and alternative energy.

The new policy provides an explicit link to our strategic priorities as a
longer-term measure. The committee believes that the relative RRR
measure does not fit with the group’s strategic focus on ‘value over
volume’.

The environmental underpin for performance shares will include
consideration of issues around carbon and climate change.

Remuneration in the wider group
Some shareholders have asked about the relationship between executive
director pay with the wider BP employee base.

The committee has considered this relationship in a number of ways:

• Any percentage increase in executive directors’ salaries will not

exceed the wider employee population.

• Pension plans for the current executive directors have been scrutinized
by the committee. The committee is satisfied that these plans should
remain in place on the terms set out in the report, on the basis that
they are open to broader groups of employees in the same home
country and any discretion (e.g. payment in lieu of pension) is also
applicable to wider groups of employees below executive level.

• The ratio between GCE and employee pay, see page 96.

Discretion
Discretion and judgement remain features of the new policy and the
committee has a clear understanding of the views of shareholders in
respect of their use.

More information

Our strategy
Page 14

Implementation of 2017 policy
Page 87

2017 proposed policy
Page 101

BP Annual Report and Form 20-F 2016Directors’ remuneration report

Implementation of 2017 policy

Salary and beneﬁts

The committee noted that salary increases for UK and US based
employees across the group were generally between 3-4%.

Salary increases over the last ﬁve years

Bob Dudley

Dr Brian Gilvary

Bob Dudley has informed the committee that he does not intend to
accept a salary increase for 2017 and therefore his salary will remain
unchanged. His salary has not been increased since 1 July 2014.

Following the AGM, Dr Brian Gilvary’s salary will be increased by
3.75%, which does not exceed increases within the broader employee
population. This increase reflects the changes made to his role in 2016
when he took on additional responsibilities for BP’s trading and shipping
functions.

Benefits for 2017 will remain broadly unchanged from prior years.

2017

Nil

2016

Nil

2015

Nil

2014

2013

Bob Dudley
Dr Brian Gilvary

3.0%

2.8%

2017

2016

Nil

2015

Nil

2014

2013

Salary with
effect from AGM
$1,854,000
£759,000

3.75%

3.0%

2.9%

Increase
Nil
3.75%

Annual bonus

For 2017, the bonus measures will focus on three areas: safety,
reliable operations and financial performance.

This approach is intended to provide a balanced assessment of how
the business has performed over the course of the year against stated
objectives. Targets are aligned with the annual plan and strategic
and operational priorities for the year.

The safety element has been simplified to focus on measures that are
robust and can be readily benchmarked against sector peers. In addition,
the measures linked to reliable operations also require execution of good
safety practices.

Although the detail of the targets is currently commercially sensitive,
the committee intends to continue to provide retrospective disclosure
following the year end.

In order to provide a fair assessment of underlying performance,
changes in plan conditions (including oil and gas prices and refining
margins) are considered when reviewing financial outcomes.

Awards will be subject to malus and clawback provisions as set out in
the policy.

The maximum bonus opportunity is 225% of salary for a bonus
scorecard of 2.0 out of 2.0. As noted in the policy, the bonus payable for
performance which meets the annual plan (i.e. a bonus scorecard of 1.0
out of a maximum of 2.0) has been reduced by 25% to half of maximum.

For any bonus earned, 50% will be delivered in cash and 50% must
be deferred into shares that will vest after three years.

The committee retains overall discretion to review outcomes in the
context of overall performance.

Measures for 2017 annual bonus

Element

Safety

20%

Measures
include

Reliable operations

Financial performance

Metric weighting
for 2017

30%

Measures
include

Metric weighting
for 2017

50%

Measures
include

Metric weighting
for 2017

Recordable injury
frequency

10%

Upstream operating
efficiency

Tier 1 process safety events

10%

Downstream refining
availability (Solomon Associates’
operational availability)

15%

Operating cash flow (excluding
Gulf of Mexico oil spill payments)

Underlying replacement
cost profit

20%

Upstream unit production costs

10%

BP Annual Report and Form 20-F 2016Corporate governanceFuture growth
Measures for the strategic element are aligned with the company’s long-
term strategy, positioning the portfolio for resilience and future growth.
We will be following the implementation of our strategy through the four
measures relating to the strategic priorities set out below. The
committee has also sought input from the board regarding the specific
measures.

Details of the strategic priorities targets – determining 20% of the
performance shares available – are commercially sensitive and are not
included in this report. However, the committee intends to provide
detailed retrospective disclosure after the end of the performance
period so that shareholders can understand the basis of payment.

Performance shares

The measures for 2017 performance share awards now focus on
shareholder value, capital discipline and future growth.

Shareholder value
The total shareholder return (TSR) element will continue to be measured
on a relative basis against the oil majors: Chevron, ExxonMobil, Shell and
Total. The committee has reviewed the current comparator group and
believes that it remains appropriate as it is used for benchmarking across
a range of activities in other parts of the group. There will be no vesting
of this element if BP’s TSR is positioned below third place in the group.

Capital discipline
Return on average capital employed (ROACE) will be calculated by
dividing the underlying replacement cost profit (after adding back net
interest) by average capital employed excluding cash and goodwill.

This assessment will be based on the final year of the three-year period.

Targets for TSR and ROACE measures for 2017 – determining 80% of
the performance shares available – are set out below at the start of the
assessment period.

Measures for 2017 performance shares

Element

Relative TSR versus oil majorsa

Return on average capital employedb

Strategic progress

50%

30%

20%

Threshold
vesting

Maximum
vesting

25% of element
Third out of five

100% of element
First place

0% of element
6% return on average capital employed

• Shift to gas and advantaged oil in the

upstream

100% of element
11% return on average capital employed

• Market led growth in the

downstream

• Venturing and low carbon across

multiple fronts

• Gas, power and renewables trading

and marketing growth

a Nil vesting for fourth and fifth place. Vesting of 80% for second place.
b Based on performance in 2019. There will be straight-line vesting for performance between the threshold and maximum vesting level. Adjustments may be required in certain
circumstances (e.g. to reflect changes in accounting standards).

Operation of the performance share plan
Prior to approving vesting outcomes the committee will additionally take
into account the broader performance of the business including absolute
TSR performance, together with safety and environmental factors over
the three-year period.

The maximum opportunity for share awards will be 500% of salary for
Bob Dudley and 450% of salary for Dr Brian Gilvary. This represents a
significant reduction from the previous long-term variable pay
opportunity – delivered via awards of performance and matching shares
on the deferred annual bonus – of 700% of salary for Bob Dudley and
550% of salary for Dr Brian Gilvary.

Performance will be measured over three years, with any vested shares
being subject to a mandatory holding period for a further three years.

Awards will be subject to malus and clawback provisions as set out in
the policy.

BP Annual Report and Form 20-F 2016Directors’ remuneration report – implementation of 2017 policyDirectors’ remuneration report – implementation of 2017 policy

Retirement beneﬁts

Bob Dudley and Dr Brian Gilvary participate in the pension
arrangements which are available to wider groups of employees
in the US and UK, as set out below.

Bob Dudley
Bob Dudley is provided with pension benefits and retirement savings
through a combination of tax-qualified and non-qualified benefit plans,
consistent with applicable US tax regulations.

The BP supplemental executive retirement benefit plan (SERB) is a
non-qualified pension plan which provides a pension of 1.3% of final
average earnings (as defined in plan rules) for each year of service, less
benefits paid under all other BP (US) tax-qualified and non-qualified
pension plans. Final average earnings include base salary, cash bonus
and bonus deferred into a share award under the deferred element of
the EDIP. Service, including service with TNK-BP, is limited to 37 years.
Bob Dudley completed 37 years of service in September 2016 and
therefore will not receive any further service accrual under these
arrangements. There will be no additional payment in lieu of any further
service accrual.

The benefit payable under the SERB is unreduced at age 60 or above.

Bob Dudley is also a member of other tax-qualified and non-qualified
pension plans. However, the benefits from those plans are offset against
the SERB benefit and so his benefit entitlement is determined by his
participation in the SERB.

The BP Employee Savings Plan (ESP) is a US tax-qualified section
401(k) plan to which both Bob Dudley and BP contribute. BP matches
contributions by Bob Dudley 1:1 up to 7% of eligible pay up to an IRS
limit. The BP Excess Compensation (Savings) Plan (ECSP) is a non-
qualified retirement savings plan under which BP provides a notional
match in respect of eligible pay that exceeds the IRS limit. In common
with other participants, Bob Dudley does not contribute to the ESCP.
From 2017 onwards, for the purposes of both plans, eligible pay for Bob
Dudley is base salary only.

Under both tax-qualified and non-qualified savings plans, Bob Dudley
is entitled to make investment elections, involving an investment in
the relevant fund in the case of the ESP and a notional investment (the
return on which would be delivered by BP under its unfunded
commitment) in the case of the ECSP.

Benefits payable under non-qualified plans are unfunded and therefore
paid from corporate assets. Benefits are generally paid as a lump sum,
with any pension benefit being converted to a lump sum equivalent.

Shareholding requirements

Both executive directors meet the share ownership requirements
of five times salary.

It is expected that Bob Dudley and Dr Brian Gilvary will maintain a
shareholding of at least 250% of salary for two years following
retirement.

Dr Brian Gilvary
Dr Brian Gilvary participates in a UK final salary pension plan, the BP
Pension Scheme (BPPS), in respect of service prior to 1 April 2011. The
BPPS provides a pension of one sixtieth of final base salary for each year
of service, up to a maximum of two thirds of final base salary, and a
dependant’s benefit of two thirds of the member’s pension.

Since 1 April 2011, Dr Brian Gilvary has, along with some other
participants in the BPPS, elected to receive a cash supplement in lieu of
future service pension accrual in the BPPS. In 2016 Dr Brian Gilvary
received a cash supplement of 35% of base salary. It has been agreed
for all participants who have elected to receive a cash supplement,
including Dr Brian Gilvary, that a transition will take effect from April
2021 when the level of cash supplement will progressively reduce to
15% of base salary by 2024.

Pension benefits in excess of the individual lifetime allowance set by
legislation are provided to Dr Brian Gilvary via an unapproved, unfunded
pension arrangement provided directly by the company.

The rules of the BPPS were amended in 2006 to introduce a normal
retirement age of 65, but in common with other BPPS participants in
service on 30 November 2006, Dr Brian Gilvary has a normal retirement
age of 60.

If Dr Brian Gilvary were to retire between age 55 and 60, then subject
to the consent of the committee, he would be entitled to an immediate
pension, with a reduction (currently 3%) for each year before normal
retirement age in respect of the benefit that relates to service since
1 December 2006 and no reduction in respect of the remainder of his
benefit.

Irrespective of this, on leaving in circumstances of total incapacity,
an immediate unreduced pension would be payable as from his
leaving date.

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementation

Single figure for 2016 – executive directors

Single ﬁgure of remuneration for executive directors in 2016 (audited)

Remuneration is reported in the currency
in which the individual is paid

Salary and benefits

Salary

Benefits

Annual bonus

Bonus earned

Less: amount deferred and at risk subject to future performancea

Performance shares

Legacy: deferred bonus and matchd

Total remuneration

Retirement benefits

Bob Dudley

(thousand)

Dr Brian Gilvary

(thousand)

2016

2015

2016

2015

$1,854

$74

$1,854

$119

£732

£67

£732

£53

$2,545

($848)

$4,172

($2,781)

£1,004

£1,646

(£335)

(£1,097)

$3,713b

$2,015

$9,353

$6,890c

$2,603

$12,857

£1,387b

£2,229c

£1,046

£3,901

£1,272

£4,835

Pension and retirement savings – value increasee

Cash in lieu of future accrual

Total including pension

$2,205

$6,519

–

£256

–

£256

$11,558

$19,376

£4,157

£5,091

Bob Dudley’s total including pension for 2016 is equivalent to £8.57 million based on the average dollar-sterling exchange rate for 2016.

a This reflects the portion of the annual bonus which is deferred into shares and will only vest subject to achievement of future performance as described below.
b Represents the assumed vesting of shares in 2017 following the end of the relevant performance period, based on a preliminary assessment of performance achieved under the rules of the
plan and includes reinvested 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 2016
which was £4.73 for ordinary shares and $35.39 for ADSs. The final vesting will be confirmed by the committee in second quarter 2017 and provided in the 2017 directors’ remuneration report.
c In accordance with UK regulations, in the 2015 single figure table, the performance outcome value was based on an estimated vesting at an assumed share price of £3.72 for ordinary shares
and $33.81 for ADSs. In April 2016, after the external data became available, the committee reviewed the relative reserves replacement ratio position. This resulted in an adjustment to the
final vesting from 77.6% to 74.3%. On 28 April 2016, 205,731 ADSs for Bob Dudley and 583,571 shares for Dr Brian Gilvary vested at prices of $33.49 and £3.82 respectively. The 2015
values for the total vesting have decreased by $226,330 for Bob Dudley and increased by £6,065 for Dr Brian Gilvary.
d Value of vested deferred bonus and matching shares. The amounts reported for 2016 relate to the 2013 annual bonus deferred over three years, which vested on 24 February 2017 at the
market price of £4.47 for ordinary shares and $33.50 for ADSs and include reinvested dividends on shares vested. There was an additional accrual of notional dividends on 31 March 2017
which will vest in 2017 and will be provided in the 2017 directors’ remuneration report. The amounts reported for 2015 relate to the 2012 annual bonus.
e Represents (1) the annual increase net of inflation in accrued pension multiplied by 20 as prescribed by UK regulations, and (2) the aggregate value of the company match under Bob Dudley’s
US retirement savings arrangements. Full details are set out on page 94.

Bob Dudley

Overall pay down
40%

Performance pay downb
32%

Dr Brian Gilvary

Overall pay down
18%

Performance pay downb
23%

b Bonus and performance shares.

Key outcomes for 2016

Bob Dudley – total pay

A year of progress
and performance
for the company.

Total single ﬁgure in
2016 for Bob Dudley is
$11.6 million – 40%
lower than for 2015.

$19.4m

Committee discretion
reduced pay by
$2.2 million.

Maximum opportunity
for 2017 and beyond
signiﬁcantly reduced.

$13.8m

$11.6m

2015

2016
Formulaic
outcome

2016
Outcome after
committee discretion

BP Annual Report and Form 20-F 2016Pay and performance for 2016

Salary and beneﬁts

Base salary
No salary increases were awarded to executive directors for 2016.
The 2016 salaries therefore remained unchanged from 1 July 2014:
$1,854,000 for Bob Dudley and £731,500 for Dr Brian Gilvary.

Annual bonus

The targets for the 2016 annual bonus were set at the start of the year
based on a combination of safety and value based measures. Targets
were set in the context of the group’s strategy and the annual plan.

During 2016 BP’s share price performed strongly and the group
distributed $7.5 billion to shareholders in cash and scrip dividends.
However, it has clearly been another challenging year for the industry.

Over the course of 2016, the oil price averaged $44 per barrel, and both
gas prices and refining margins remained weak compared to historic
levels. In this context, the group’s operating cash flow was solid. Goals
for reduction in controllable costs were delivered one year ahead of
schedule, and there has been good discipline on capital expenditure.

Trends in safety and environmental measures continued to be positive
with outperformance against targets for tier 1 process safety events and
recordable injury frequency. The outcome for loss of primary containment
was partly impacted by harsher winter operating conditions in our
unconventional gas operations in the US, and therefore the threshold set
was not met. Although there was no payment against this performance
measure, the committee noted that the 2016 outcomes did not create any
safety concerns and that the longer-term trend for the measure remained
positive.

More generally, good progress was made during 2016 to create
a platform for future growth: the remaining material uncertainties
regarding Deepwater Horizon liabilities have now been clarified; visible
progress has been made in a number of upstream projects; and in our
downstream business we rolled out our biggest fuels launch in a
decade.

When reviewing performance over the period, the committee also
sought input from the chairs of the audit committee and the safety,
ethics and environment assurance committee to ensure a
comprehensive review of peformance.

Overall, the performance delivered during the year resulted in a
scorecard outcome of 1.22. Under the policy applicable for the year,
approved by shareholders in 2014, this scorecard outcome would
have resulted in a bonus outcome equal to 81% of the maximum
available.

Beneﬁts
Executive directors received car-related benefits, security assistance,
insurance and medical benefits.

The committee considered the overall outcome and noted that while
performance during the second and third quarters was strong, there
were some challenges during the final quarter. The committee exercised
discretion and applied some of the principles of the new policy early. As
a result, the bonus of 81% of maximum based on the previous formulaic
outcome was reduced to 61% of the maximum annual bonus available.

Overall, the committee believes that the bonuses for 2016 fairly reflect
performance over the period.

Outcome

Name
Bob Dudley
Dr Brian Gilvary

Adjusted outcome
after committee
discretion
(thousand)
$2,545a
£1,004

Paid
in cash
(thousand)
$1,696
£669

Deferred
into BP
shares
(thousand)
$848
£335

a Due to rounding, the total does not agree exactly with the sum of its component parts.

Under the terms of the existing directors’ remuneration policy applicable
for 2016, directors mandatorily defer a third of their bonus and could
volunteer to defer a further third; the deferred portion of the annual
bonus is then matched with a further performance-based award. The
deferred and matching awards vest subject to a safety and
environmental sustainability performance hurdle.

As a transition to the new policy, for 2016 the executive directors will
defer a third of their bonus but will not have the opportunity to increase
the potential matching award by voluntarily increasing the proportion of
their bonus to be deferred.

In addition, with the support of the committee, the executive directors
have elected to extend the vesting period for their matching awards in
respect of the compulsorily deferred 2016 bonus, so that vesting will not
occur until after retirement rather than the normal three-year period.
During this extended period, the matching award will remain subject to
the performance hurdle. The committee is of the view that this is a
positive step as it significantly increases the time horizons for
management’s incentives, and reinforces the emphasis on stewardship,
safety and the environment which remain core priorities for the group.

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementationDirectors’ remuneration report – implementation

Annual bonus – continued

Scorecard

2016 annual bonus

1 Safety
0.36

Measures

Safety

Loss of primary containment

Tier 1 process safety events

Recordable injury frequency

Safety outcome

Value

Operating cash flow (excluding
Gulf of Mexico oil spill payments)

Underlying replacement
cost proﬁt

Corporate and functional
costs

Major project delivery

Value outcome

Total bonus score

More information

Key performance indicators page 18

Value
0.86

Formulaic score
1.22 out of 2.0

Threshold 0
performance and score

Plan/target 1.0
performance and score

Maximum 2.0
performance and score

Performance and
outcome

230 events
0

25 events
0

0.253/200k hrs
0

214 events
0.1

22 events
0.1

0.232/200k hrs
0.1

182 events
0.2

15 events
0.2

0.191/200k hrs
0.2

$14.8bn
0

$2.1bn
0

$4.04bn
0

2
0

$16.8bn
0.3

$2.9bn
0.25

$3.74bn
0.1

4
0.05

$18.8bn
0.6

$3.7bn
0.5

$3.44bn
0.2

6
0.1

233 events
0

16 events
0.19

0.202/200k hrs
0.17

0.36

$17.6bn
0.42

$2.6bn
0.16

$3.49bn
0.18

6
0.10

0.86

1.22 out of 2.0

Bonus after
discretion 61%
of maximum

Application of the score
The maximum annual bonus available to be paid is 225% of salary. By using the
methodology under the 2014 policy, a score of 1.22 would result in payment of 81% of that
maximum. The committee has used discretion to reduce the payment from 81% to 61%.

BP Annual Report and Form 20-F 2016Performance shares

For performance shares awarded in 2014, vesting was determined by a
combination of relative TSR, safety, financial and operational performance
assessed over the three years from 2014 to 2016. The results are
summarized in the table below.

Measured over the three-year period, the company’s TSR was in third place
amongst the five oil majors. The committee noted that returns on the value
of BP’s shares in sterling have also risen by 22% over this period,
outperforming returns on the FTSE 100 index over the same timeframe.

The group delivered positive scores for tier 1 process safety events and
recordable injury frequency. As noted above, the outcome for loss of primary
containment was partly impacted by harsher winter operating conditions in
our unconventional gas operations in the US. While the threshold for this
element was not met, the outcomes did not create any safety concerns and
the longer-term trend for the measure remains positive. The nil outcome
provides an indication of the stretch of the original target range set.

In respect of project delivery, the vesting outcome reflects the strong
progress over the three-year period. Further details of performance are set
out in the strategic report.

Preliminary assessment of relative reserves replacement ratio indicates
vesting for this measure. For the purpose of this report, a forecast has been
used. The final outcome for this measure will be confirmed later in the year,
once competitor data is published in full.

Scorecard

2014-2016 performance shares
Vesting % of the 2014 award

For operating cash flow, the hurdle for full vesting was originally set at
$34.9 billion, based on an assumed oil price of $105 per barrel.

Under the methodology used and disclosed in prior years, this target would
have been adjusted to reflect the price environment in 2016, when the actual
average oil price was $44 per barrel. The adjusted target would mean that
60% of the award would vest for $15.3 billion, with full vesting occurring at
$19.3 billion. The performance in 2016 would have resulted in a vesting
outcome of just over 80% of the maximum available for this part of the
award.

However, in light of shareholder feedback in 2016, the committee
determined that it would be appropriate to exercise its discretion on this
part of the award to ensure that the overall vesting outcome fairly reflected
the performance of the business and outcomes for shareholders.

The committee undertook a wider review of performance over the
three-year performance period, with additional consultation with the chairs
of the audit committee and the safety, ethics and environment assurance
committee. Following this review of performance, the committee
determined that the vesting for the 2016 award should be reduced from
the formulaic outcome of 57% of maximum to 40% of maximum.

More information

Key performance indicators page 18

1 Financial
35.9%

Measures

1 Financial

Relative total shareholder return

Operating cash flow (excluding
Gulf of Mexico oil spill payments)

Strategic imperatives

Relative reserves
replacement ratio

Major project delivery

Safety and operational risk

– Loss of primary containment

– Tier 1 process safety events

– Recordable injury frequency

Total formulaic vesting

Vesting after committee judgement

Strategic imperatives
21.1%

Total formulaic vesting
57%

Weighting at
maximum %

Threshold
performance

Maximum
performance

Performance
and outcome

33.3

11.1

3.7

Third

First

See discussion above

Third

First

210 events

172 events

23 events

15 events

0.265/200k hrs

0.215/200k hrs

Third
8.3%

$17.6bn
27.6%

35.9%

Third
2.8%

17
11.1%

233 events
0%
16 events
3.5%

0.202/200k hrs
3.7%

21.1%

57%

Vesting after
discretion 40%

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementationPerformance shares – continued

Preliminary outcome – 2014-2016 performance shares

Name
Bob Dudley
Dr Brian Gilvary

Shares awarded
1,304,922
605,544

Shares vesting
including dividends
629,484
293,296

Value of
vested shares
$3,712,906
£1,387,290

These values are based on forecast vesting levels. As noted above, final
vesting will be determined once competitor data is published in respect
of relative reserves replacement.

Legacy: deferred bonus and matching award

Both Bob Dudley and Dr Brian Gilvary deferred one third of their 2013
annual bonus in accordance with the terms of the deferred bonus plan.

The three-year performance period for this deferred award ended on
31 December 2016.

The committee reviewed safety and environmental sustainability
performance over this period and sought the input of the safety, ethics
and environment assurance committee. This included an assessment of
both actual outcomes under safety and sustainability measures and also
consideration of the long-term performance trend.

Over the three-year period 2014-2016 safety performance continued to
demonstrate progress and improvement. The committee also noted
the extent to which safety performance had become embedded into
the culture of the organization and the degree to which this has
supported stronger operational and financial performance. This

Conclusions of the safety and sustainability assessment

2013-2015 performance shares – ﬁnal outcome
Last year the committee made a preliminary assessment of first
place for the relative RRR in the 2013-2015 performance shares
element.

In April 2016 the committee reviewed the results for all comparator
companies as published in their annual reports and assessed that BP
was in second place relative to other oil majors and that 7.8% of shares
– out of a maximum of 11.1% – would vest for this performance
measure. This resulted in a final overall vesting of 74.3% of maximum
instead of the preliminary outcome of 77.6% outlined in the 2015
directors’ remuneration report.

strengthened safety performance has also informed the committee’s
thinking when including safety measures in pay arrangements under the
new policy.

Following the committee’s review, full vesting of the deferred and
matching shares in respect of the 2013 deferred bonus was approved.

Subject to approval of the new policy, which will be presented to
shareholders at the 2017 AGM, the committee does not intend
to grant further matching share awards under this plan.

2013 deferred bonus vesting – outcome

Name
Bob Dudley
Dr Brian Gilvary

Shares
deferred
299,256
193,306

Total shares
including
Vesting
dividends
agreed
100% 360,900
100% 234,070

Total value at
vesting
$2,015,025
£1,046,293

No systemic
issues identified

No major incidents

Safety culture and values
embedded within the
global organization

Strong performance supports
efficiency and financial results
across the group

Retirement beneﬁts

2016 outcomes
Bob Dudley participates in the US pension and retirement savings plans
described on page 89. In 2016, Bob Dudley’s accrued pension
increased, net of inflation, by $59,000. This increase has been reflected
in the single figure table on page 90 by multiplying it by a factor of 20
in accordance with the requirements of the UK regulations (giving
$1,185,000).

In relation to the retirement savings plans, Bob Dudley made
contributions in 2016 to the ESP totalling $26,500. For 2016 the total
value of BP matching contributions in respect of Bob Dudley to the ESP
and notional matching contributions to the ECSP was $422,000, 7% of
eligible pay. After adjusting for investment gains within his accumulating
unfunded ECSP account (aggregating the unfunded arrangements
relating to his overall service with BP and TNK-BP) the amount included
in the single figure table on page 90 is $1,020,000.

Dr Brian Gilvary participates in the UK pension arrangements described
on page 89. In 2016 Dr Brian Gilvary’s accrued pension did not increase.
In accordance with the requirements of the UK regulations, the value
shown in the single figure table on page 90 is zero. He has exceeded the
lifetime allowance under UK pensions legislation and, in accordance
with the policy, receives a cash supplement of 35% of base salary,
which has been separately identified in the single figure table on
page 90.

The committee continues to keep under review the increase in the value
of pension benefits for individual directors.

BP Annual Report and Form 20-F 2016Directors’ remuneration report – implementationStewardship
The committee places significant emphasis on executive directors
having material interests in the shares of the company. Such
shareholding not only provides direct alignment with the experience
of shareholders, but also encourages a longer-term focus when
considering the performance of BP. Executive directors are required to
build a personal shareholding of five times salary within five years of
their appointment.

Both executive directors significantly exceed the minimum holding
required. This ensures they are subject to any fluctuation in the share
price and the wider shareholder experience.

Post-retirement share ownership interests
Given the long-term nature of the group’s operations, the committee
sees the merits of ensuring that executives have performance alignment
beyond the timeframe of existing incentive plans. The executive
directors have taken a number of steps in this respect.

• Firstly, the current executive directors have indicated to the committee
that they expect to maintain a shareholding of at least 250% of salary
for two years following retirement.

• Secondly, as noted above, for deferred awards granted in respect of
the 2016 bonus, Bob Dudley and Brian Gilvary have agreed to delay
vesting of awards of matching shares until after retirement, rather
than the normal three-year period.

• Thirdly, Bob Dudley has further voluntarily opted to delay the vesting of
all outstanding deferred bonus and matching shares in respect of his
2014 and 2015 bonus (representing a total interest over 1,691,784
ordinary shares), which were originally due to vest in 2018 and 2019
respectively, so that vesting is delayed until after retirement.

These factors significantly extend the time horizons for both executive
directors, and in particular Bob Dudley. The committee fully endorses
the steps taken by both executive directors as they clearly demonstrate
a continued commitment to the long-term stewardship of the group.

Directors’ shareholdings
The table below shows the status of each of the executive directors in
developing the required level of share ownership. These figures include
the value as at 22 March 2017 of the directors’ interests shown below
excluding the assumed vesting of the 2014-2016 performance shares.

Current directors
Bob Dudley

Appointment date
October 2010

Value of current
shareholding
$15,298,423

Dr Brian Gilvary

January 2012

£7,018,143

% of policy
achieved
165

191

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 (DTRs) as at the applicable dates.

Ordinary
shares or
Ordinary shares
equivalents at
or equivalents
at 1 Jan 2016
31 Dec 2016
1,554,198 2,509,500
1,419,263

903,856

Changes from
31 Dec 2016 to
22 March 2017
191,016
124,034

Ordinary shares
or equivalents
total at
22 March 2017
2,700,516
1,543,297

Current directors
Bob Dudleya
Dr Brian Gilvary

a Held as ADSs.

The following table shows both the performance shares and the
deferred bonus element awarded under the executive directors’
incentive plan (EDIP) and yet to vest. 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.

Ordinary
shares or
equivalents at
1 Jan 2016
5,536,950
2,789,921

Ordinary
shares or
equivalents at
31 Dec 2016
6,607,314
3,259,891

Changes from
31 Dec 2016 to
22 March 2017
(299,256)
(193,306)

Ordinary shares
or equivalents
total at
22 March 2017
6,308,058
3,066,585

Current directors
Bob Dudleya
Dr Brian Gilvary

a Held as ADSs.

At 22 March 2017, the following directors held options under the
BP group share plan schemes over ordinary shares or their calculated
equivalent set out below. None of these are subject to performance
conditions. Additional details regarding these plans can be found on
page 100.

Current director
Dr Brian Gilvary

Share options
503,103

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 22 March 2017,
all directors and other members of senior management as a group held
interests of 13,080,536 ordinary shares or their calculated equivalent,
9,619,319 restricted share units (with or without conditions) or their
calculated equivalent, 9,374,643 performance shares or their calculated
equivalent and 5,513,021 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
58-59 for further information.

Further information

Historical TSR performance

FTSE 100

£250

£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

2015

2016

This graph shows the growth in value of a hypothetical £100 holding in
BP p.l.c. ordinary shares over eight years, relative to a hypothetical £100
holding in the FTSE 100 Index of which the company is a constituent.

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementation

Directors’ remuneration report – implementation

History of GCE remuneration

Year
2009
2010c

2011
2012
2013
2014
2015
2016

Total

remuneration
thousanda
£6,753
£3,890
$8,057
$8,439
$9,609
$15,086
$16,390
$19,376
$11,558

Annual bonus
% of
maximum
89b
0
0
67
65
88
73
100
61

Performance
shares vesting
% of maximum
17.5
0
0
16.7
0
45.5
63.8
74.3
40

GCE
Hayward
Hayward
Dudley
Dudley
Dudley
Dudley
Dudley
Dudley
Dudley

a Total remuneration figures include pension. The total figure is also affected by share vesting
outcomes and these amounts represent the actual outcome for the periods up to 2011 or the
adjusted outcome in subsequent years where a preliminary assessment of the performance
for EDIP was made. For 2016, the preliminary assessment has been reflected.
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 GCE until October 2010.

Relative importance of spend on pay ($ million)

Distributions to
shareholders

Remuneration paid to
all employeesa

Capital investmentb

18,440

18,748

12,928

11,233

7,469

7,301

2016

2015

2016

2015

2016

2015

Total

2.3%

13.1%

Total

1.6%

a Total remuneration reflects overall employee costs. See Financial statements – Note 34
for further information.
b Capital investment reflects organic capital expenditure. 2016 includes Abu Dhabi onshore oil
concession renewal.

GCE-to-employee pay ratio
The committee wanted to understand the GCE-to-employee pay
ratio at BP when developing the policy. The ratio can vary significantly
depending on the calculation methodology and sample employee
population used and therefore can evolve over time.

The most relevant comparator group is the professional/managerial
grade employees based in the UK and US which represent some 22%
of the global employee population and is used elsewhere in this report.
GCE-to-median-worker pay ratio for this sample was 71 to 1 in 2016.
The ratio is based on a comparison of total compensation (base salary,
actual annual bonus and vested equity awards) in the year. The
committee will review the progression of the pay ratio over time.

Percentage change in GCE remuneration

Comparing 2016 to 2015
% change in GCE remuneration
% change in comparator group
remuneration

Salary

Benefits

-38.1%

Bonus

-39.0%

3.5%a

3.0%

-7.6%

a The comparator group comprises some 22% 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.

Independence and advice
The board considers all committee members to be independent
with no personal financial interest, other than as shareholders, in the
committee’s decisions. Further detail on the activities of the committee,
including activities during the year, advice received and shareholder
engagement is set out in the remuneration committee report on
page 76.

During 2016 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.

Gerrit Aronson, an independent consultant, was the committee’s
independent adviser until April 2016. He was engaged directly by the
committee. Willis 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.

Following a competitive tender process, the committee appointed
Deloitte LLP as its independent adviser in May 2016. Deloitte is a
member of the Remuneration Consulting Group and, as such, operates
under the code of conduct in relation to executive remuneration
consulting in the UK. The committee is satisfied that the advice received
is objective and independent.

Both firms provide other advice in their respective areas to the group.
During the year, the wider Deloitte firm also provided BP with services
including consulting on HR and Upstream matters.

In October 2016, BP completed a tender of its statutory audit and
selected Deloitte as BP’s auditor for the financial year 2018.
Consequently, Deloitte will step down as adviser to the committee
during 2017.

Total fees or other charges (based on an hourly rate) for the provision of
remuneration advice to the committee in 2016 (save in respect of legal
advice) are as follows:

Gerrit Aronson £45,000
Willis Towers Watson £5,000
Deloitte £262,000

BP Annual Report and Form 20-F 2016Shareholder engagement
As set out in the committee chairman’s letter, during the last year we
had extensive dialogue with many of our largest shareholders as well as
representative bodies on remuneration matters. We have listened and
sought to respond to their concerns.

Following the vote at the 2016 AGM the committee is proposing a
number of changes to our remuneration policy for future years to
respond to shareholder concerns.

The table below shows the votes on the report for the last three years.

AGM directors’ remuneration report vote results

Year
2016
2015
2014

% vote ‘for’
40.7%
88.8%
83.9%

% vote ‘against’

Votes withheld
59.3% 464,259,340
11.2% 305,297,190
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
2014

% vote ‘for’
96.4%

% vote ‘against’

Votes withheld
3.6% 125,217,443

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 2016 are shown below.

Additional
position
held at
appointee company
Director
L’Air Liquide Non-executive director

Appointee
company
Rosnefta

Total fees
0
€47,333

Director
Bob Dudley
Dr Brian Gilvary

a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft.

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 2016.

Chairman
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 car and driver, and
security advice in London. He receives a contribution to an ofﬁce and
secretarial support as appropriate to his needs in Sweden.

Chairman

Fees
£ thousand
785

The table below shows the fees paid for the chairman for the year ended
31 December 2016.

2016 remuneration (audited)

£ thousand

Carl-Henric Svanberg

Fees

Beneﬁtsa

Total

2016
785

2015
785

2016
58

2015
38

2016
843

2015
823

a Beneﬁts include travel and other expenses relating to 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 1,203%.

Ordinary
shares or
equivalents at
1 Jan 2016

Ordinary
shares or
equivalents at
31 Dec 2016

Change from
31 Dec 2016
to
22 March 2017

Ordinary
shares or
equivalents
total at
22 March 2017

2,076,695

–

2,076,695

Chairman
Carl-Henric
Svanberg

Non-executive directors
Fee structure
The table below shows the fee structure for non-executive directors:

Senior independent directora
Board member
Audit, geopolitical, remuneration and
SEEA committees chairmanship feesb
Committee membership feec
Intercontinental travel allowance

Fees
£ 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 Committee chairmen do not receive an additional membership fee for the committee
they chair.
c For members of the audit, geopolitical, SEEA and remuneration committees.

21A_2017_03_22_34642_BP_ARA_DRR_VERSION_B_p80_110.indd 97

06/04/2017 16:47:23

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementation

Directors’ remuneration report – implementation

2016 remuneration (audited)

£ thousand

Fees

Benefitsa

Total

Nils Andersenb
Paul Anderson
Alan Boeckmann
Admiral Frank Bowman
Antony Burgmansc
Cynthia Carroll
Ian Davis
Professor Dame Ann
Dowlingd
Brendan Nelson
Phuthuma Nhlekoc
Paula Rosput Reynoldse
Sir John Sawers
Andrew Shilston

2016
23
165
168
162
47
140
136

150
130
48
140
148
190

2015
–
177
178
177
149
127
145

141
125
167
93
85
165

2016
6
32
17
14
21
28
2

2
30
3
17
19
5

2015
–
28
14
12
19
68
3

1
11
11
8
0
3

2016
29
197
185
176
68
168
138

152
160
51
157
167
195

2015
–
205
192
189
168
195
148

142
136
178
101
85
168

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.
b Appointed on 31 October 2016.
c Retired on 14 April 2016.
d In addition, Professor Dame Ann Dowling received £25,000 for chairing and being a member
of the BP technology advisory council.
e The 2015 number has been restated to reflect tax treatment.

The geopolitical committee was established in late 2015. Its members received the first full year of fees in 2016.

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.

Nils Andersena
Paul Anderson
Alan Boeckmann
Admiral Frank Bowman
Antony Burgmansc
Cynthia Carroll
Ian Davis
Professor Dame Ann Dowling
Brendan Nelson
Phuthuma Nhlekoc
Paula Rosput Reynolds
Sir John Sawers
Andrew Shilston

a Appointed on 31 October 2016.
b Held as ADSs.
c Retired on 14 April 2016.

Ordinary shares
or equivalents at
1 Jan 2016
–
30,000b
44,772b
24,864b
10,156
10,500b
23,854
22,320
11,040
–
52,200b
13,528
15,000

Ordinary shares
or equivalents at
31 Dec 2016
47,855
30,000b
44,772b
24,864b
–
10,500b
25,735
22,320
11,040
–
52,200b
13,528
15,000

Change from
31 Dec 2016 to
22 March 2017
52,145
–
–
–
–
–
–
–
–
–
6,000
–
–

Ordinary shares
or equivalents
total at
22 March 2017
100,000
30,000b
44,772b
24,864b
–
10,500b
25,735
22,320
11,040
–
58,200b
13,528
15,000

Value of
current
shareholding
£454,750
$169,950
$253,633
$140,855
–
$59,483
£117,030
£101,500
£50,204
–
$329,703
£61,519
£68,213

% of policy
achieved
505
140
209
116
–
49
130
113
56
–
271
68
57

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 2016, he received £100,000 for this role.

BP Annual Report and Form 20-F 2016Executive directors

Deferred shares (audited)a

Bob Dudleyb

Dr Brian Gilvary

2013

Bonus
year
2012

Type
Comp
Vol
Mat
Comp
Mat
2014d Comp
Vol
Mat
2015e Comp
Vol
Mat
Comp
Vol
Mat
Comp
Mat
2014d Comp
Vol
Mat
2015e Comp
Vol
Mat

2013

2012

Former executive directors
Iain Conn

2012 Comp
Vol
Mat
2013 Comp
Mat
2012 Comp
Vol
Mat

Dr Byron Groteb

Performance
period
2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
2015-2017g
2015-2017g
2015- 2017g
2016-2018g
2016-2018g
2016-2018g
2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
2015-2017
2015-2017
2015-2017
2016-2018
2016-2018
2016-2018

2013-2015
2013-2015
2013-2015
2014-2016
2014-2016
2013-2015
2013-2015
2013-2015

Date of award of
deferred shares
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
11 Feb 2015
11 Feb 2015
11 Feb 2015
4 Mar 2016
4 Mar 2016
4 Mar 2016
11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
11 Feb 2015
11 Feb 2015
11 Feb 2015
4 Mar 2016
4 Mar 2016
4 Mar 2016

11 Feb 2013
11 Feb 2013
11 Feb 2013
12 Feb 2014
12 Feb 2014
11 Feb 2013
11 Feb 2013
11 Feb 2013

Deferred share element interests
Potential maximum deferred shares

At 1 Jan
2016
114,690
114,690
229,380
149,628
149,628
147,054
147,054
294,108
–
–
–
78,815
78,815
157,630
96,653
96,653
88,288
88,288
176,576
–
–
–

80,648
80,648
107,531f
100,563
33,521f
97,278
97,278
32,424f

Awarded

2016
–
–
–
–
–
–
–
–
275,892
275,892
551,784
–
–
–
–
–
–
–
–
159,021
159,021
318,042

–
–
–
–
–
–
–
–

At 31 Dec
2016
–
–
–
149,628
149,628
147,054
147,054
294,108
275,892
275,892
551,784
–
–
–
96,653
96,653
88,288
88,288
176,576
159,021
159,021
318,042

–
–
–
100,563
33,521f
–
–
–

Interests vested in 2016 and 2017

Number of
ordinary shares
vested

–
–
–
–
–
–

Vesting date
134,856c 9 Feb 2016
134,856c 9 Feb 2016
269,712c 9 Feb 2016
180,450c 24 Feb 2017
180,450c 24 Feb 2017
–
–
–
–
–
–
95,226c 9 Feb 2016
95,226 c 9 Feb 2016
190,453c 9 Feb 2016
117,035c 24 Feb 2017
117,035c 24 Feb 2017
–
–
–
–
–
–

–
–
–
–
–
–

97,441c 9 Feb 2016
97,441c 9 Feb 2016
129,922c 9 Feb 2016
121,770c 24 Feb 2017
40,590c 24 Feb 2017
114,384c 9 Feb 2016
114,384c 9 Feb 2016
38,124c 9 Feb 2016

£
Face value
of the award
–
–
–
–
–
655,861
655,861
1,311,722
1,015,283
1,015,283
2,030,565
–
–
–
–
–
393,764
393,764
787,529
585,197
585,197
1,170,395

–
–
–
–
–
–
–
–

Comp = Compulsory.
Vol = Voluntary.
Mat = Matching.
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 February 2016 and 24 February 2017 were £3.34 and £4.47 respectively and for
ADSs on 9 February 2016 and 24 February 2017 were $28.95 and $33.50 respectively.
d The face value has been calculated using the market price of ordinary shares on 11 February 2015 of £4.46.
e The market price at closing of ordinary shares on 4 March 2016 was £3.68 and for ADSs was $31.15. The sterling value has been used to calculate the face value.
f 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.
g Bob Dudley has voluntarily agreed to defer vesting of these awards until after retirement. Therefore the performance period is expected to exceed the minimum term of three years.

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – implementationDirectors’ remuneration report – implementation

Executive directors

Performance shares (audited)

Share element interests

Interests vested in 2015 and 2016

Bob Dudleyb

Dr Brian Gilvary

Performance period
2013-2015
2014-2016
2015-2017e
2016-2018e
2013-2015
2014-2016
2015-2017e
2016-2018e

Date of award
of performance
shares
11 Feb 2013
12 Feb 2014
11 Feb 2015
4 Mar 2016
11 Feb 2013
12 Feb 2014
11 Feb 2015
4 Mar 2016

Potential maximum performance sharesa

At 1 Jan
2016
1,384,026
1,304,922
1,501,770
–
637,413
605,544
685,246
–

Awarded
2016
–
–
–
1,809,582
–
–
–
786,559

At 31 Dec
2016
–
1,304,922
1,501,770
1,809,582
–
605,544
685,246
786,559

Number of
ordinary
shares
vested

–
–

Vesting date
1,234,386c 28 Apr 2016d
629,484c May 2017
–
–
583,571c 28 Apr 2016d
293,296c May 2017
–
–

–
–

£
Face value
of the award
–
–
6,697,894
6,659,262
–
–
3,056,197
2,894,537

Former executive directors
Iain Conn

Dr Byron Groteb

2013-2015
2014-2016
2013-2015

11 Feb 2013
12 Feb 2014
11 Feb 2013

463,126
220,043
142,278

–
–
–

–
220,043f
–

424,006c 28 Apr 2016d
106,578c May 2017
126,894c 28 Apr 2016d

–
–
–

a For awards under the 2013-2015, 2014-2016, 2015-2017 and 2016-2018 plans, performance conditions are measured one third on TSR relative to 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 44.4%, which is conditional on the TSR, operating cash flow and each 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 28 April 2016 was £3.82 and for ADSs was $33.49. For the assumed vestings dated May 2017 a price of £4.73 per ordinary share
and $35.39 per ADS has been used. These are the average prices from the fourth quarter of 2016.
d The 2013-2015 award vested on 28 April 2016, which resulted in an increase in value at vesting of £4,405 for Iain Conn and a decrease of $23,233 for Byron Grote. Details for Bob Dudley and
Brian Gilvary can be found in the single figure table on page 90.
e The market price at closing of ordinary shares on 11 February 2015 was £4.46 and for ADSs was $40.35 and on 4 March 2016 was £3.68 and for ADSs was $31.15.
f 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 options plans (audited)

Dr Brian Gilvary

Option type At 1 Jan 2016
500,000
BP 2011
4,191
SAYE
–
SAYE

Granted
–
–
3,103

Exercised
–
4,191
–

At 31 Dec
2016
500,000
–
3,103

Option price
£3.72
£3.68
£2.90

Market price at
date of exercise

Date from which
first exercisable

Expiry date
– 07 Sep 2014 07 Sep 2021
£4.35 01 Sep 2016 28 Feb 2017
– 01 Sep 2019 28 Feb 2020

The closing market prices of an ordinary share and of an ADS on 31 December 2016 were £5.10 and $37.38 respectively.
During 2016 the highest market prices were £5.11 and $37.40 respectively and the lowest market prices were £3.10 and $27.64 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 plan.

100

BP Annual Report and Form 20-F 2016Directors’ remuneration policy

Set out below is our directors’ remuneration policy
(the ‘policy’) for 2017 and subsequent years. It will be
presented to shareholders at the 2017 annual general
meeting and, subject to shareholder approval, will take

effect for the 2017 financial year. We have developed
this policy following a fundamental review of
remuneration arrangements and extensive consultation
with our major shareholders.

Remuneration principles
Remuneration principles

BP is a global company with a global management team, competing
for talent in a demanding environment. The company’s ability to attract
and retain the high calibre executives required to lead a global and
highly complex business is important for shareholders.

The policy has been designed to reflect the global nature of BP’s
business and talent pool. The competitive market for top executives

both within the oil and gas sector and more broadly provides an
important reference point, but is only one of a number of factors
considered when the company sets pay.

The following principles underpin BP’s revised approach to remuneration
for executive directors.

Simplification

Link to strategy

Shareholder alignment

Stewardship

• Simpler, transparent and fair

approach.

• Substantial proportion is variable
and linked to the delivery of BP’s
strategy.

• Package is intended to vary with

performance.

• Outcomes are intended to reflect

• Focus on long-term

performance.

• Pay is intended to reflect
shareholder experience.

sustainable performance.

• Emphasis on share ownership.

Key changes

The policy is intended to provide a simpliﬁed approach with a
clear link between delivery of BP’s strategy and pay, while
reflecting outcomes for shareholders.

The policy has been simplified and clarified in response to shareholder
feedback. Certain elements have been updated to reflect
developments in the UK market and best practice over the past three
years. It is designed to be well-balanced and to support the priorities
for BP over the short and long term.

We have made a number of important changes to executive
directors’ remuneration which result in a significant reduction
in the overall variable remuneration opportunity. These include:

• Simplified and updated measures to provide a more balanced and
rounded assessment of group performance and better alignment
with outcomes for shareholders.

• Removal of the matching arrangements for the deferred

annual bonus.

• A revised structure so that the annual bonus pay-out scale will
be more demanding in future years. Payment for on-target
performance is reduced and the maximum bonus will only
be paid if there is outperformance on all targets.

• A higher mandatory deferral of annual bonus awards into BP shares

from one third to one half of any annual bonus earned. These will vest
after three years with no voluntary deferral or match.

• Reduction in the GCE’s maximum opportunity for performance

shares from 550% of salary to 500%.

• Together with the elimination of matching shares this reduces
the total maximum available under long-term remuneration
(i.e. performance and matching shares) from 700% to 500%
of salary for the GCE and from 550% to 450% of salary for the CFO.

• Stronger malus and clawback provisions.

• Removal of duplicate measures between the annual and long-term

elements.

Consideration of shareholder views

In designing the policy the committee undertook a major
review of remuneration, considering how pay would support
BP’s strategy and better align with shareholders’ interests.

Engagement with major shareholders has been key to this review and
the committee chair has consulted with shareholders beginning in May
2016 and running through to this year’s AGM. This multi-stage
approach was adopted for the committee to hear and reflect on
shareholder feedback while developing the new policy. In direct
response to the views received, the policy has been refined over a
number of months.

We have valued this dialogue with shareholders and remain
committed to ensuring a clear and transparent approach to pay.
This policy is designed to provide a transparent framework through
which shareholders can assess the basis on which the executive
directors at BP are paid.

101

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyDirectors’ remuneration report – policy

Remuneration policy table – executive directors

Salary and beneﬁts

Purpose

Operation and
opportunity

Performance
framework

Annual bonus

Purpose

To provide fixed remuneration to reflect the scale and complexity of both the business
and the role, and to be competitive with the external market.

Beneﬁts
• The committee expects to maintain benefits at the

current level.

• Executive directors are entitled to receive those

benefits available to all BP employees generally, such
as participation in all-employee share plans, sickness
pay, relocation assistance and maternity pay.
Benefits are not pensionable.

• Executive directors may receive other benefits that are
judged to be cost effective and appropriate in terms of
the individual’s role, time and/or security. These include
car-related benefits or cash in lieu, driver, security,
assistance with tax return preparation, insurance and
medical benefits. The company may meet any tax
charges arising on business-related benefits provided
to directors, for example security.

• The taxable value of benefits provided may fluctuate
during the period of this policy, depending on the cost
of provision and a director’s personal circumstances.

Salary
• Salary levels take into account the nature of the role,
performance of the business and the individual,
market positioning and pay conditions in the wider
BP group. When setting salaries, the committee
considers practice in other oil and gas majors as well
as European and US companies of a similar size,
geographic spread and business dynamic to BP.
• Salaries are normally set in the home currency of the
executive director and are reviewed annually. They
may be reviewed at other times where appropriate,
for example following a major role change.

• Salary levels are specific to the role and individual and

therefore there is no maximum salary under the policy.
However, when reviewing salaries for executive
directors, the committee will consider salary increases
for the most senior management and for employees in
relevant countries. Percentage increases for executive
directors will not exceed that of the broader employee
population, other than in specific circumstances
identified by the committee (e.g. in response to a
substantial change in responsibilities).

• Following the 2017 AGM, the annual salaries for the

executive directors will be:

– Group chief executive – Bob Dudley: $1,854,000.
– Chief financial officer – Dr Brian Gilvary: £759,000.

• Not applicable

To provide variable remuneration dependent on performance against annual financial,
operational and safety measures. 50% of the bonus is paid in cash and 50% is mandatorily
deferred and held in BP shares for three years to reinforce the long-term nature of the
business and the importance of sustainability.

Operation and
opportunity

• The bonus is based on performance against annual
measures and targets set at the start of the year,
evaluated over the financial year and assessed
following the year end.

• 50% of the bonus earned is required to be deferred

into BP shares for three years. Dividends (or
equivalents, including the value of any reinvestment)
may accrue in respect of any deferred shares.

• Awards are subject to malus and clawback provisions

as described on page 105.

• Typically the annual bonus earned would be 50% of
the maximum available for delivery of performance
in line with the annual plan. The level of bonus
payable may vary depending on the nature of the
performance measure and level of target set.
• Executive directors may earn a maximum annual

bonus (including any deferral) of up to 225% of salary
for stretching performance against the objectives set
for the year. The committee intends to set demanding
requirements for maximum payment.

Performance
framework

• The committee determines specific measures,
weightings and targets each year to reflect the
priorities in the annual plan, which is designed
to deliver the group’s strategy and is approved
by the board.

• Measures will typically include a balance of financial,

operational and safety measures. Details of the
measures will be reported in advance each year in the
annual report on remuneration. The committee intends
to disclose targets for the annual bonus retrospectively.

102

BP Annual Report and Form 20-F 2016

Performance shares

Purpose

Operation and
opportunity

Performance
framework

To link the largest part of remuneration opportunity with the long-term performance
of the business. The outcome varies with performance against measures linked directly to
strategic priorities.

• Annual awards of shares will vest based on

performance relative to measures and targets that
reflect the delivery of BP’s strategy. Performance
will normally be measured over a period of at least
three years.

• The maximum annual award level for the group chief
executive will be 500% of salary and 450% of salary
for the chief financial officer.

• Performance shares will only vest to the extent that
performance targets are met. The level of vesting
for performance will depend on the stretch of the
objective set, but the threshold level would normally

• Performance shares may vest based on a

combination of total shareholder return, financial
and strategic measures.

• For 2017 awards, the measures and weightings will be:
– total shareholder return relative to oil and gas

majors (50%)

– return on average capital employed (30%)
– strategic progress (20%)

• Details of 2017 targets relating to the total shareholder

return and return on average capital employed
measures are outlined in the remuneration report.
Details relating to strategic progress will be disclosed
retrospectively.

not be expected to exceed 25% of the maximum
opportunity for the relevant element.

• Once performance has been measured, a proportion
of the shares that will vest are subject to a holding
period. The combined length of the performance and
holding periods will be normally six years.

• Dividends (or equivalents, including the value of

reinvestment) may accrue in respect of vested shares.
• Awards are subject to malus and clawback provisions

as described on page 105.

• Prior to granting each award the committee will review
the measures, weightings and targets to ensure they
remain focused on delivering the strategy and are in
the interests of shareholders.

• At least 40% of any award will be subject to measures
linked to shareholder returns and the proportion linked
to strategic progress will not exceed 30%. The
committee would consult appropriately with major
shareholders regarding any material changes to the
measures.

Shareholding requirements

Purpose

To provide alignment between the interests of executive directors and our other shareholders.

Operation and
opportunity

Performance
framework

Retirement beneﬁts

• An executive director is expected to build up and

maintain a minimum shareholding of five times their
base salary within five years of their appointment.

• Not applicable.

Purpose

To recognize competitive practice in home country.

Operation and
opportunity

• Executive directors normally participate in the company
retirement plans that operate in their home country.

• Senior executives in BP have generally been employees
of the group for a number of years. They often remain
participants in long-standing arrangements in which
other group employees continue to participate, but
which are no longer offered to new employees. The
maximum opportunity will vary depending on the terms
of these arrangements.

• UK participants may remain members of the company’s
defined benefit plan. In common with other employees
in this plan, they may choose to receive up to 35% of
salary in lieu as a cash supplement but do not receive
further service accrual under this plan.

The level of this allowance is expected to reduce in
future, in line with the proposed reduction for other UK
employees who participate in this arrangement.
• US executive directors participate in long-standing plans
of Amoco and Arco and other BP defined benefit and
retirement savings plans for US employees.

• For future appointments, the committee will carefully
review any retirement benefits to be granted to a new
director. This will take account of retirement policies
across the wider group, any arrangements currently
in place, local market practice and individual
circumstances. The committee will consider
retirement benefits in the context of the overall
approach to remuneration.

Performance
framework

• Retirement benefits in the UK are not directly linked to

performance. Reflecting local market practice,

legacy arrangements in the US may reference
bonuses when determining the benefit level.

103

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyDirectors’ remuneration report – policy

Notes to the policy table

How is variable pay linked to performance under the new policy?

Annual bonus

Performance shares

Share ownership

50% paid in cash; 50% in BP
shares deferred for 3 years

6 years: 3-year performance
period + 3-year holding period

Built up over 5 years
and maintained

The three elements described above provide a balance between focus on short-term, medium-term and long-term performance, while
encouraging behaviours which are in the long-term interests of shareholders.

The operation of variable pay is supported by a focus on stewardship. There is an expectation that executives will build up a holding of five
times salary over a period of five years following appointment and maintain that level during employment.

How are performance measures linked to the strategy under the new policy?

Variable pay is linked to performance measures designed to deliver the BP strategy. At the start of each year, the remuneration committee reviews
the measures, targets and weightings to ensure they remain consistent with the priorities in the annual plan and the group strategy. For the annual
bonus and performance shares, the approach to performance measurement is intended to provide a balance of measures to assess performance
reflecting the global scale of the business and unique characteristics of the oil and gas sector.

The measures for the 2017 awards are summarized below, with further detail set out in the annual report on remuneration on pages 87-88.

New remuneration policy measures for period commencing in 2017

Annual bonus

Safety

20%

Recordable injury frequency

Tier 1 process safety events

Performance shares

Relative TSR

50%

TSR relative to five oil and
gas majors

Rankings:

1st = 100% of award
2nd = 80%
3rd = 25%

Reliable operations

Financial performance

30%

Upstream operating efficiency
Downstream refining availability
(Solomon Associates’ operational
availability)

50%

Operating cash flow (excluding Gulf of
Mexico oil spill payments)

Underlying replacement cost profit

Upstream unit production costs

Return on capital employed

Strategic progress

30%

Absolute ROACE (with target
disclosed in advance)
Evaluation will be based on final
year of three-year period

20%

Based on a balanced assessment of
performance against key strategic
priorities.

Underpin: Take into account absolute TSR and safety/environmental factors prior to determining ﬁnal vesting outcome.

Discretion to reflect broader environment

Robust malus and clawback

• The annual bonus is determined based on performance against

measures and targets from the annual plan, which is designed to
implement BP’s strategy. Performance measures include a range of
financial, operating and safety metrics.

• Measures for performance share awards provide alignment with
shareholder returns and long-term sustainable performance.
• The combination of measures provides a diverse and rounded

assessment of performance with appropriate checks and balances.
• The committee reviews BP’s underlying performance and external
market reference points, as well as performance against specific
measures and targets. It also seeks input from the board’s audit and
safety, ethics and environmental assurance committees on relevant

aspects before determining final outcomes. For the performance share
awards, the committee will consider longer-term safety and
environmental performance as an underpin when evaluating outcomes.
This will take into account both absolute shareholder returns and safety
and environmental factors, including consideration of issues around
carbon and climate change, prior to determining the actual vesting levels.

• When appropriate, the committee may make adjustments, upwards
or downwards, to a straight formulaic outcome based on the group’s
broader performance and the outcomes for shareholders. The
committee considers that this informed judgement is important
to establishing an overall assessment of performance.

104

BP Annual Report and Form 20-F 2016Long-term shareholdingBonus aligned with annual objectivesShare award for meeting three-year targets
How will we use flexibility, judgement and discretion?

The committee is empowered to make quantitative and qualitative
assessments of performance in reaching its decisions. This involves the
use of judgement and discretion within a transparent framework
approved by shareholders. The committee continues to consider that
the powers of flexibility, judgement and discretion are critical to the
successful execution of the policy.

In framing the policy, the committee has taken care to ensure that
these important powers continue to be available:

• Sufficient flexibility to take account of future changes in the industry
environment and in remuneration practice generally. This allows the
committee to respond to changes in circumstances, for example in
applying particular performance measures within the plans which may
need to evolve with the company’s strategy, without the need for
specific shareholder approval.

• Power to exercise judgement in making a qualitative assessment in

certain circumstances. A number of measures are used for annual or
long-term incentive awards, many of which are numerical in nature
and require a quantitative assessment of performance. Others may
require a qualitative assessment.

How will we safeguard against payments for failure?

• Scope for the committee to exercise discretion, mainly where it is
desirable to vary a formulaic outcome that would otherwise arise
from the policy’s implementation. The committee considers that the
ability to exercise discretion, upwards or downwards, is important
to ensure that a particular outcome is fair in light of the director’s
own performance, the company’s overall performance and positioning
under particular performance measures and outcomes for
shareholders. In accordance with UK regulations, areas where the
remuneration policy provides for the exercise of discretion are
identified in this report.

The committee intends to provide appropriate disclosure on the use of
discretion so that shareholders can understand the basis for its
decisions.

Performance
based pay

Discretion

Malus and
clawback

• A significant portion of remuneration varies with

performance – where performance targets are not
achieved, lower or no payments will be made under
the plans.

• The committee may vary formulaic outcomes where
these do not suitably reflect performance over the
relevant performance period.

• The malus provisions enable the committee to

• The clawback provisions enable the committee to

reduce the size of award, cancel an unvested award,
or impose further conditions on an award made
under this policy.

require participants to return some or all of an award
after payment or vesting. They may be applied under
the following circumstances:

• The malus provisions may apply if, prior to the

− incorrect outcomes due to miscalculation or based

vesting or payment of an award, there is a negative
event such as:

on incorrect information

− restatement due to financial reporting failure or

− material failure impacting safety or environmental

misstatement of audited results

− material misconduct by the participant.

sustainability

− incorrect award outcomes due to miscalculation

or based on incorrect information

− restatement due to financial reporting failure or

misstatement of audited results

− material misconduct by the participant

− such other exceptional circumstances that the
committee consider to be similar in nature.

105

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyDirectors’ remuneration report – policy

Illustration of application of remuneration policy

The total remuneration opportunity for executive directors is strongly performance based and weighted to the long term. The charts below provide
scenarios for the total remuneration of executive directors at different levels of performance and are calculated as prescribed in UK regulations.

Bob Dudley

Min

100%

$2.33m

Dr Brian Gilvary

Min

100%

£1.09m

Mid

26%

23%

51%

$9.05m

Mid

30%

23%

47%

£3.65m

Max

15%

26%

59%

$15.77m

Max

18%

27%

55%

£6.21m

Fixed pay

Annual bonus

Performance shares

Fixed pay

Annual bonus

Performance shares

Component
For these illustrations base salary, beneﬁts and pension are the same in all three scenarios

Base salary

GCE: $1,854,000
CFO: £759,000

Benefits and
retirement benefits

GCE: $474,000
CFO: £332,000

Based on salary effective following the AGM.

Benefits are based on the value shown in the 2016 single figure table.

Mr Dudley’s assumed pension value is based on illustrative returns from his retirement
savings plans.

Dr Gilvary’s retirement benefits assume an allowance of 35% of salary.

Component
Variable pay under the new policy comprises annual bonus and performance shares

Scenario

Minimum

Mid

Maximum

Annual bonus
(including cash and
deferred elements)

Performance
sharesb

Threshold not met

Nil

Threshold not met

GCE – Nil
CFO – Nil

50% of maximum

112.5% of salary

50% vestinga

GCE – 250% of salary
CFO – 225% of salary

100% of maximum

225% of salary

100% vesting

GCE – 500% of salary
CFO – 450% of salary

a Note that this is an indicative figure. The average vesting level for BP performance shares between 2010-2016 was 34%.
b Amounts in respect of performance shares and deferred annual bonus are shown at face value excluding the impact of share price growth and dividends.

106

BP Annual Report and Form 20-F 2016Recruitment policy

The committee expects any new executive director to be engaged on
terms that are consistent with the policy. However it recognizes that it
cannot anticipate circumstances in which any new executive director
may be recruited. The committee may determine that it is in the
interests of the company and shareholders to secure the services
of a particular individual which may require it to take account of the
terms of that individual’s existing employment and/or their personal
circumstances.

Accordingly, the committee will ensure that:

• The salary level of any new director is appropriate to their role and
the competitive environment at the time of appointment. Where
appropriate it may appoint an individual on a lower salary, then
gradually increase salary levels as the individual gains experience
in the role.

• Variable remuneration will be awarded within the parameters of

the policy.

• The committee may tailor the vesting criteria for initial incentive

awards depending on the specific circumstances.

• Where an existing employee is promoted to the board, the company

may honour all existing contractual commitments including any
outstanding share awards or pension entitlements.

• The committee would expect any new director to participate in the

company pension and benefit schemes that are open to other senior
employees (where appropriate referencing the candidate’s home
country) but would take into account the director’s existing
arrangements and market norms.

Service contract

• Where an individual is relocating in order to take up the role, the

company may provide certain one-off benefits such as reasonable
relocation expenses, accommodation for a period following
appointment, assistance with visa applications or other immigration
issues and ongoing arrangements such as tax equalization, annual
flights home and a housing allowance.

• Where an individual would be forfeiting remuneration or employment

terms in order to join the company, the committee may award
appropriate compensation. The committee would require reasonable
evidence of the nature and value of any forfeited arrangements and
would, to the extent practicable, ensure any compensation was of
comparable commercial value and capped as appropriate, taking into
account the terms of the previous arrangement being forfeited (for
example the form and structure of award, timeframe, performance
criteria and likelihood of vesting). Where appropriate, the committee
would have a preference for buy-outs to be delivered in the form of
shares in the company.

In making any decision on the remuneration of a new director, the
committee would balance shareholder expectations, current best
practice and the circumstances of any new director. It would strive
not to pay more than is necessary to recruit the right candidate and
would give full details in the next remuneration report.

Bob Dudley’s service contract is with BP Corporation North America Inc.
Dr Brian Gilvary’s service contract is with BP p.l.c.

The employer may lawfully terminate the executive director’s
employment in the following ways:

Each executive director is entitled to pension provision as outlined on
page 103.

Each executive director is also entitled to the following contractual
benefits:

• For security reasons, a company car and driver is provided for business
and private use. The company will bear all normal servicing, insurance
and running costs.

• Medical and dental benefits, sick pay during periods of absence and

assistance with the preparation of tax returns.

• Indemnification in accordance with applicable law.

• Participation in bonus or incentive arrangements at the committee’s

sole discretion.

Each executive director may terminate their employment by giving 12
months’ written notice. In this event, for business reasons, the employer
may not necessarily hold the executive director to their full notice period.

• By giving the director 12 months’ written notice.

• Without compensation, in circumstances where the employer is

entitled to terminate for cause, as defined for the purposes of their
service contract.

Additionally, in the case of Dr Brian Gilvary, the company may lawfully
terminate employment by making a lump sum payment in lieu of notice
equal to 12 months’ base salary or by monthly instalments rather than as
a lump sum.

The lawful termination mechanisms described above are without
prejudice to the employer’s ability in appropriate circumstances to
terminate in breach of the notice period referred to above, and thereby to
be liable for damages to the executive director.

In the event of termination by the company, each executive director may
have an entitlement to compensation in respect of their statutory rights
under employment protection legislation in the UK and potentially
elsewhere. Where appropriate the company may also meet a director’s
reasonable legal expenses in connection with either their appointment
or termination of their appointment.

107

BP Annual Report and Form 20-F 2016Corporate governanceDirectors’ remuneration report – policyTermination payments

In determining overall termination arrangements, the committee
will distinguish between types of leaver and the circumstances
of their leaving.

The committee would also consider all relevant circumstances,
including whether a contractual provision in the director’s arrangements
complied with best practice at the time of termination and the date
the provision was agreed, as well as the performance of the director
in certain respects.

Where appropriate, the committee may consider providing certain
benefits relating to termination including the provision of outplacement
support or costs associated with relocation back to an individual’s
home country.

Should it become necessary to terminate an executive director’s
employment, and therefore to determine a termination payment,
the committee’s policy is as follows:

Termination
payments

Annual bonus

Share awards

• The director’s primary entitlement would be a
termination payment in respect of their service
agreement, as set out above. However the
committee will consider mitigation to reduce the
termination payment where appropriate to do so,
taking into account the circumstances for leaving and
the terms of the agreement. Mitigation would not be
applicable where a contractual payment in lieu of
notice is made.

• If the departing director is eligible for an early

retirement pension, the committee would consider,
if relevant under the terms of the appropriate plan,
the extent of any actuarial reduction that should be
applied. UK directors who leave in circumstances
approved by the committee may have a favourable
actuarial reduction applied to their pensions (which to
date has been 3%). Departing directors who leave in
other circumstances may be subject to a greater
reduction.

• The committee would consider whether the director
should be entitled to an annual bonus in respect of
the financial year in which the termination occurs.

Normally, any such bonus would be restricted to the
director’s actual period of service in that financial
year.

• In deciding whether to exercise discretion to

preserve EDIP awards, the committee would also
consider the proximity of the award to its maturity
date.

• Share awards will be treated in accordance with the
relevant plan rules. For awards granted under the
Executive Directors’ Incentive Plan (EDIP), the
treatment can only be made in accordance with the
framework approved by shareholders.

• The committee would consider whether conditional
share awards held by the director should lapse on
leaving or should, at the committee’s discretion, be
preserved. If awards are preserved, the award would
normally continue until the vesting date. Awards may
be pro-rated based on service over the performance
period.

108

BP Annual Report and Form 20-F 2016Directors’ remuneration report – policyDirectors’ remuneration report – policy

Legacy arrangements and other detailed provisions

Previously the deferred element of the annual bonus in respect of years
up to and including 2016 attracted a corresponding award of matching
shares. Although the committee will no longer grant matching awards in
respect of future bonus awards, executives retain interests in legacy
awards previously granted under this arrangement under the terms set
out in the 2014 policy.

For completeness, the table below summarizes the key terms of the
previous matching share element.

Legacy incentives: deferred bonus and matching shares (no further awards to be granted)

Purpose

Operation

To reinforce the long-term nature of the business and the importance of sustainability.

• Previously one third of the annual bonus was

• Where shares vest, additional shares representing

subject to compulsory deferral and a further third
was subject to voluntary deferral.

• These deferred shares were matched on a

one-for-one basis.

Performance
framework

• Both deferred and matching shares must pass an

additional hurdle related to safety and environmental
sustainability performance in order to vest.

the value of reinvested dividends are added.
• All deferred shares are subject to clawback

provisions if they are found to have been granted on
the basis of a material misstatement of financial or
other data.

• If there has been a material deterioration in safety
and environmental metrics, or major incidents
revealing underlying weaknesses in safety and
environmental management then the committee,
with advice from the board’s safety, ethics and
environmental assurance committee, may conclude
that shares vest in part, or not at all.

In addition to the award described above, the committee may continue
to satisfy existing remuneration commitments and/or payments for loss
of office, including the exercise of any discretion in connection with such
payments provided that such terms were agreed:

• before 10 April 2014 when the first approved remuneration policy

came into effect

• before the 2017 policy came into effect, provided that the terms of the
payment were consistent with the shareholder-approved directors’
remuneration policy in force at the time they were agreed

• at a time when the relevant individual was not a director of the

company and, in the opinion of the committee, the payment was not
in consideration for the individual becoming a director.

Share awards are subject to the terms of the relevant plan rules under
which the award has been granted. The committee may adjust or
amend awards, but only in accordance with the provisions of the plan
rules. This includes making adjustments to awards to reflect one-off
corporate events, such as a change in the company’s capital structure or
treatment of awards in the event of a change of control. In accordance
with the plan rules, awards may be settled in cash rather than shares,
where the committee considers this appropriate.

The committee may make minor amendments to the policy to aid its
operation or implementation without seeking shareholder approval, for
example for regulatory, exchange control, tax or administrative purposes
or to take account of a change in legislation provided that any such
change is not to the material advantage of the directors.

Remuneration in the wider group

The committee considers employment conditions in the BP group when
establishing and implementing policy for executive directors to ensure
the alignment of and context for principles and approach. In particular,
the committee reviews the policy for the most senior leaders.

The wider employee group participates in performance-based
incentives. Throughout the group, base salary and benefit levels are set
in accordance with the prevailing relevant market conditions and practice
in the countries in which employees are based.

Decisions regarding remuneration for employees outside the group
leaders are the responsibility of the GCE. The committee does not
consult directly with employees when formulating the policy.
However, feedback from employee surveys, that are regularly
reported to the board, provide views on a wide range of employee
matters including pay.

Differences between executive director pay policy and that of other
employees reflect the senior position of the individuals, prevailing
market conditions and corporate governance practices in respect
of executive director remuneration. The key difference in policy for
executive directors is that a greater proportion of total remuneration
is delivered as performance-based incentives.

109

BP Annual Report and Form 20-F 2016Corporate governanceRemuneration policy table – non-executive directors

Non-executive chairman

Fees

Approach

Remuneration is in the form of cash fees, payable monthly. The level and structure of the chairman’s remuneration will
primarily be compared against UK best practice.

Operation and
opportunity

The quantum and structure of the non-executive chairman’s remuneration is reviewed annually by the remuneration
committee, which makes a recommendation to the board.

Beneﬁts and expenses

Approach

Operation and
opportunity

The chairman is provided with support and reasonable travelling expenses.

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 his home country as appropriate. A car and the use of a driver 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.

Non-executive directors

Fees

Approach

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 level and structure of
non-executive directors’ remuneration will primarily be compared against UK best practice.

Additional fees may be payable to reflect additional board responsibilities, for example, committee chairmanship and
membership and for the role of senior independent director.

Operation and
opportunity

The level and structure of non-executive directors’ remuneration is reviewed by the chairman, the GCE and the
company secretary who make a recommendation to the board. Non-executive directors do not vote on their own
remuneration.

Remuneration for non-executive directors is reviewed annually.

Other fees and beneﬁts

Intercontinental allowance

Approach

Operation and
opportunity

Benefits and expenses

Non-executive directors receive an allowance to reflect the global nature of the company’s business. The intercontinental
travel allowance is payable for the purpose of attending board or committee meetings or site visits.

The allowance is paid in cash following each event of intercontinental travel.

Approach

Non-executive directors are provided with administrative support and reasonable travelling expenses.

Professional fees are reimbursed in the form of cash, payable following the provision of advice and assistance.

Operation and
opportunity

Non-executive directors are reimbursed for all reasonable travelling and subsistence expenses (including any relevant
tax) incurred in carrying out their duties.

The reimbursement of professional fees incurred by non-executive directors based outside the UK in connection with
advice and assistance on UK tax compliance matters.

The maximum fees for non-executive directors are set in accordance with the Articles of Association.

This directors’ remuneration report was approved by the board and signed on its behalf by David J Jackson, company secretary on 6 April 2017.

110

BP Annual Report and Form 20-F 2016Directors’ remuneration report – policyDirectors’ statements

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.

Risk management and internal control
Under the UK Corporate Governance Code (Code), the board is responsible
for the company’s risk management and internal control systems. In
discharging this responsibility the board, through its governance principles,
requires the group chief executive to operate the company with a
comprehensive system of controls and internal audit to identify and
manage the risks that are material to BP. In turn, the board, through its
monitoring processes, satisfies itself that these material risks are identified
and understood by management and that systems of risk management
and internal control are in place to mitigate them. These systems are
reviewed periodically by the board, have been in place for the year under
review and up to the date of this report and are consistent with the
requirements of principle C.2 of the Code.

The board has processes in place to:

• assess the principal risks facing the company.
• monitor the company’s system of internal control (which includes
the ongoing process for identifying, evaluating and managing the
principal risks).

• review the effectiveness of that system annually.

Non-operated joint ventures and associates have not been dealt with as
part of this board process.

A description of the principal risks facing the company, including those that
could potentially threaten its business model, future performance, solvency
or liquidity, is set out in Risk factors on page 49. During the year, the board
undertook a robust assessment of the principal risks facing the company.
The principal means by which these risks are managed or mitigated are set
out in How we manage risk on page 47.

In assessing the risks faced by the company and monitoring the system of
internal control, the board and the audit, safety, ethics and environment
assurance and geopolitical committees requested, received and reviewed
reports from executive management, including management of the
business segments, corporate activities and functions, at their regular
meetings. A report by each of these committees, including its activities
during the year, is set out on pages 64-78.

During the year, the committees also met with management, the group
head of audit and other monitoring and assurance functions (including
group ethics and compliance, safety and operational risk, group control,
group legal and group risk) and the external auditor. Responses by
management to incidents that occurred were considered by the
appropriate committee or the board.

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.

A board meeting in February 2017 carried out an annual review of the
effectiveness of the system of internal control. In considering this system,
the board noted that it is 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.

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.

• 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.

This review included a report from the group head of audit which
summarized 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 internal audit work
conducted during the year and the remedial actions taken by management
in response to failings and weaknesses identified. Where failings or
weaknesses were identified, the board was satisfied that these were or
are being appropriately addressed by the remedial actions proposed by
management.

A statement regarding the company’s internal controls over financial
reporting is set out on page 267.

C-H Svanberg
Chairman
6 April 2017

This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

111

BP Annual Report and Form 20-F 2016Corporate governanceLonger-term viability
In accordance with provision C.2.2 of the Code, the directors have
assessed the prospects of the company over a period significantly longer
than 12 months. The directors believe that an assessment period of three
years is appropriate based on management’s reasonable expectations of
the position and performance of the company over this period, taking
account of its short-term and longer-range plans.

Taking into account the company’s current position and its principal risks,
the directors have a reasonable expectation that the company will be able
to continue in operation and meet its liabilities as they fall due over three
years.

The directors’ assessment included a review of the financial impact of the
most severe but plausible scenarios that could threaten the viability of the
company and the likely effectiveness of the potential mitigations that
management reasonably believes would be available to the company over
this period.

In assessing the prospects of the company, the directors noted that such
assessment is subject to a degree of uncertainty that can be expected to
increase looking out over time and, accordingly, that future outcomes
cannot be guaranteed or predicted with certainty.

Going concern
In accordance with provision C.1.3 of the Code, the directors have made an
assessment of the group’s ability to continue as a going concern and
consider it appropriate to adopt the going concern basis of accounting in
preparing the financial statements.

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 position and
performance, business model and strategy.

This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

112

BP Annual Report and Form 20-F 2016Financial
statements

114 Consolidated financial statements of the BP group

Independent auditor’s
reports
Group income statement
Group statement of
comprehensive income

114
122

123

Group statement of
changes in equity
Group balance sheet
Group cash flow statement

126 Notes on financial statements

123
124
125

157

4.
5.
6.

7.
8.
9.
10.

11.

126

136

Significant accounting
policies
Significant event – Gulf of
Mexico oil spill
Non-current assets held
for sale
139
Disposals and impairment 140
Segmental analysis
142
Income statement
analysis
Exploration expenditure
Taxation
Dividends
Earnings per ordinary
share
Property, plant and
equipment

145
146
146
148

148

150
150
151
152

12. Capital commitments
13. Goodwill
14.
15.

Intangible assets
Investments in joint
ventures
153
Investments in associates 153
155
155

16.
17. Other investments
Inventories
18.
Trade and other
19.
receivables

156

20. Valuation and qualifying

accounts
156
Trade and other payables 156

21.

22.
23.

Provisions
Pensions and other post-
retirement benefits

157
24. Cash and cash equivalents 163
25.
163
26. Capital disclosures and

Finance debt

analysis of changes in net
debt

27. Operating leases
28.

Financial instruments and
financial risk factors
29. Derivative financial
instruments

30. Called-up share capital
31. Capital and reserves
32. Contingent liabilities
33. Remuneration of senior
management and non-
executive directors
Employee costs and
numbers

34.

35. Auditor’s remuneration
36. Subsidiaries, joint
arrangements and
associates

37. Condensed consolidating
information on certain US
subsidiaries

164
164

165

168
172
174
177

178

179
179

180

181

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

187 Supplementary information on oil and natural gas

(unaudited)

Oil and natural gas
exploration and production
activities
Movements in estimated
net proved reserves

188

194

Standardized measure of
discounted future net cash
flows and changes therein
relating to proved oil and
gas reserves
Operational and statistical
information

215 Parent company financial statements of BP p.l.c.

Company balance sheet
Company statement of
changes in equity
Notes on financial
statements
1.

Significant
accounting policies
Investments
Receivables
Pensions
Payables
Taxation
Called-up share
capital

2.
3.
4.
5.
6.
7.

215

216

217

217
219
220
220
223
224

224

Capital and reserves
Financial guarantees

8.
9.
10. Share-based

payments
11. Auditor’s

remuneration

12. Directors’

13.

remuneration
Employee costs and
numbers

14. Related undertakings

of the group

209

212

225
225

225

226

227

BP Annual Report and Form 20-F 2016

113

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 2016

and of the group’s profit for the year then ended;

• the group financial statements have been properly prepared in accordance with IFRS as adopted by the European Union;
• the parent company financial statements have been properly prepared in accordance with United Kingdom generally accepted accounting

practice including FRS 101 ‘Reduced Disclosure Framework’; and

• 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.

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 2016 which comprise:

Group

Parent company

Group balance sheet as at 31 December 2016.

Balance sheet as at 31 December 2016.

Group income statement for the year then ended.

Statement of changes in equity for the year then ended.

Group statement of comprehensive income for the year then ended.

Related Notes 1 to 14 to the financial statements.

Group statement of changes in equity for the year then ended.

Group cash flow statement for the year then ended.

Related Notes 1 to 37 to the financial statements.

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) including FRS 101.

Our assessment of the risks of material misstatement
We identified the risks of material misstatement described below as those that had the greatest effect on our overall audit strategy, the
allocation of resources in the audit and the direction of the efforts of the audit team. In addressing these risks, we designed and performed the
procedures below for the purpose of expressing an audit opinion on the financial statements as a whole. We do not express any opinion on
these individual risks. Other than as described, these matters are unchanged from those we reported in our 2015 audit opinion.

Risk

Our response to the risk

The determination of the liabilities, contingent
liabilities and disclosures arising from the significant
uncertainties related to the Gulf of Mexico oil spill (as
described on page 71 of the report of the audit
committee and Note 2 of the financial statements).

Following significant progress in 2016 in resolving
outstanding claims, management concluded they were
able to reliably estimate the remaining material liabilities
arising from the 2010 Deepwater Horizon incident.

There is uncertainty around estimating and valuing the
remaining outstanding business economic loss claims.
The determination of the liability is subject to judgement
as to the amount that each remaining claim will be
settled at.

For the liabilities and contingent liabilities related to the
Gulf of Mexico oil spill the primary audit engagement
team performed the following audit procedures.

• We walked through and tested the controls designed
and operated by the group relating to the provisions
and payables for the Gulf of Mexico oil spill.

• We met with the group’s legal team to understand
developments across key remaining Gulf of Mexico
oil spill matters and their status. We discussed legal
developments with the group’s external lawyers,
reviewed audit enquiry response letters from external
legal counsel and read determinations and judgments
made by the courts.

• In respect of the provision for the outstanding

business economic loss claims:
• We compared the key assumptions that have been
used in the determination of the year end provision,
to historical experience. These assumptions are the
proportion of outstanding claims that will receive a
monetary award and the average monetary claim
value.

• We reconciled the number of undetermined claims

to third party claims management data.

What we concluded to
the Audit Committee

We are satisfied
that management is
able to determine a
reliable estimate for
the remaining
business economic
loss claims and that
the disclosures
presented in relation
to contingent
liabilities are
appropriate.

Based on our
procedures we are
satisfied that the
amounts provided in
the financial
statements, as
disclosed in Note 2
of the financial
statements, are
supported by claims
experience.

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Risk

Our response to the risk

What we concluded to
the Audit Committee

The current macroeconomic environment has the
potential to materially impact the carrying value of
the group’s Upstream non-current assets (as
described on page 71 of the report of the audit
committee and Note 1 of the financial statements).

2016 has been a more uncertain political and
macroeconomic environment, influenced by significant
political and economic events.

Additionally, OPEC decisions on the production of
hydrocarbons have a significant effect on prices in global
commodity markets.

These factors combine to create additional uncertainty in
relation to key inputs into future cash flow forecasts,
which are used to project the recoverability of the
group’s tangible and intangible assets.

• We performed sensitivity analyses over average
cost per claim assumptions and assessed the
potential effect on the provision.

• With regard to Plaintiffs’ Steering Committee

settlements, we engaged EY actuarial experts to
consider the analysis of available claims data
undertaken by management. We corroborated the
data used in respect of all claim categories, with
specific regard to business economic loss, this being
the most complex to estimate. Our testing included
understanding and verifying trends in the claim
models, considering the approach in respect of all
claim categories compared with prior periods.
• We assessed the remaining economic loss and
property damage claims from individuals and
businesses that either opted out of the PSC
settlement and/or were excluded from that
settlement. We validated a sample of claims to third
party data, assessing the year end closing provision
was appropriate.

• We considered the accounting treatment of the

liabilities, contingent liabilities and disclosures under
IFRS criteria, to conclude whether these were
appropriate in all the circumstances.

We extended the scope of our original planned
procedures to address the changing risk. This included
further use of EY valuation experts in critically assessing
and corroborating, to external market data, the revised
assumptions used in impairment testing, the most
significant of these being future market oil and gas
prices and discount rates. We also focused on reserves
and resources volumes, as described elsewhere in our
report.

In addressing this risk, audit procedures were performed
by component teams at each of the group’s 10
Upstream components scoped-in for the audit of asset
impairment. In addition, the primary audit engagement
team tested certain remaining assets identified at risk of
impairment.

• We walked through and tested the controls designed
and operated by the group relating to the assessment
of the carrying value of tangible assets.

• We examined the methodology used by management

to assess the carrying value of tangible assets
assigned to cash-generating units, to determine its
compliance with accounting standards and
consistency of application.

• We assessed the centrally-derived oil and gas price

assumptions by reference to external market data and
engaged EY valuation experts to critically assess the
suitability of the revised assumptions.

• We evaluated estimates of future cash flows and

considered whether these were appropriate in light of
future price assumptions and cost budgets.

• Together with EY valuation experts we assessed

specific inputs to the determination of the discount
rate. Such inputs were benchmarked against rates
observable in the markets in which the group
operates.

• We performed procedures over the completeness of
the impairment charges and reversals and exploration
write-offs, also validating that base data used in the
impairment models agreed to the underlying books
and records.

• We checked the mathematical accuracy of the

impairment models.

BP’s oil and gas
price assumptions
are comparable to
the range seen
within the industry
at this time. The
methodology used
has been applied
consistently year on
year.

The pre-tax discount
rate of 9% (2015
11%) and the post-
tax discount rate of
6% (2015 7%) are
within our range of
expectation. The
movement year on
year is verifiable and
reasonable based
on market data.

Based on our
procedures, we
believe the
impairment charges
and certain
reversals of
previous impairment
charges recorded,
are appropriate and
in accordance with
IFRS.

Based on our
procedures on the
exploration portfolio
we consider the
write-offs were
properly recorded
and remaining
carrying values are
appropriate and in
accordance with
IFRS.

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Risk

Our response to the risk

The estimate of oil and gas reserves and resources
has a significant impact on the financial statements,
particularly impairment testing and depreciation,
depletion and amortization (‘DD&A’) charges (as
described on page 71 of the report of the audit
committee and Note 1 of the financial statements).

The estimation of oil and natural gas reserves and
resources is a significant area of judgement due to the
technical uncertainty in assessing quantities and
complex contractual arrangements dictating the group’s
share of reportable volumes.

Reserves and resources are also a fundamental indicator
of the future potential of the group’s performance.

Unauthorized trading activity within the integrated
supply and trading function has the potential to
impact revenue and profits (as described on page 71 of
the report of the audit committee and Note 1 of the
financial statements).

Unauthorized trading activity is a fraud risk associated
with a potential deliberate misstatement of the group’s
trading positions or mis-marking of positions with an
intention to:

• Minimize trading losses.
• Maximize trading profits.
• Understate profits or move profits to subsequent
periods when bonus ceilings have already been
reached, to maximize individual bonuses across
financial years.

These acts would lead to a misstatement of the group’s
revenue and profits.

Audit procedures were performed by team members
with significant experience of auditing oil and gas
reserves, including the primary audit engagement team
and component teams at 10 Upstream components.

• We tested the group’s controls over their internal
certification process for internal technical and
commercial experts who are responsible for reserves
and resources estimation.

• We assessed the competence and objectivity of the

group’s internal and external experts, to satisfy
ourselves they were appropriately qualified to carry
out the volumes estimation.

• We performed procedures to assess the reliability of

data provided to external experts.

• We confirmed that significant changes in reserves

and resources were made in the appropriate period,
and in compliance with the Discovered Resources
Management Policy (‘DRM-P’).

• Where volumetric movements had a material impact

on the financial statements, we validated these
volumes against underlying information and
documentation as required by the DRM-P, along with
checking that assumptions used to estimate reserves
and resources were made in compliance with relevant
regulations.

• We validated that the updated reserves and resources
estimates were included appropriately in the group’s
consideration of impairment and in accounting for
DD&A.

Audit procedures on revenue and trading were
performed by component teams and the primary
engagement team at 7 components across the UK, US
and Singapore.

• We walked through and tested the controls designed
and operated by the group over unauthorized trading
activity.

• We identified trades with the highest risk of

unauthorized activity so as to focus our testing on
these trades.

• We performed existence and completeness testing
by confirming a sample of trades with third parties.
• 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.

What we concluded to
the Audit Committee

Based on our
procedures we
consider that the
reserves
estimations are
reasonable for use
in the impairment
testing and
calculation of
DD&A.

Based on our
procedures we
identified no
matters to report to
the Audit
Committee.

Changes from the prior year
Our risk assessment and audit approach evolve as circumstances which impact the group’s business or financial statements change. Since the
2015 audit we have changed our assessment of the risk of material misstatement as this relates to the group’s investment in Rosneft. The
continued demonstration of significant influence by the group over Rosneft, along with the relative stabilization of the current environment in
Russia, meant that in our view the profile of this risk had reduced and no longer had a significant effect on our audit strategy or our allocation of
resources.

The scope of our audit
Tailoring the scope
Our assessment of audit risk, our evaluation of materiality and our allocation of performance materiality determine our audit scope for each entity
within the group. Taken together, this enables us to form an opinion on the consolidated financial statements. We take into account size, risk
profile, the organization of the group and effectiveness of group-wide controls, changes in the business environment and other factors such as
recent internal audit results when assessing the level of work to be performed at each component.

In scoping the audit we reflect the group’s structure (Upstream, Downstream, Rosneft and Other businesses and corporate), plus the group’s
functions. In assessing the risk of material misstatement to the group financial statements, and to ensure we had adequate quantitative
coverage of significant accounts in the financial statements, we performed full or specific scope audit procedures over 50 components covering
the UK, US, Angola, Azerbaijan, Egypt, Germany, India, Iraq, Russia, Singapore, Trinidad and the group functions, representing the principal
business units within the group.

Of the 50 components selected, we performed an audit of the complete financial information of 9 components (“full scope components”) which
were selected based on their size or risk characteristics. For the remaining 41 components (“specific scope components”), we

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performed audit procedures on specific accounts within that component that we considered had the potential for the greatest impact on the
significant accounts in the financial statements either because of the size of these accounts or their risk profile.

For the current year, the full scope components contributed 29% of the group’s loss before tax (2015 43%), 41% of the group’s revenue (2015
41%) and 10% of the group’s property, plant and equipment (2015 11%). The specific scope components contributed 32% of the group’s loss
before tax (2015 10%), 26% of the group’s revenue (2015 29%) and 54% of the group’s property, plant and equipment (2015 55%). The audit
scope of the specific scope components may not have included testing of all significant accounts of the component but will have contributed to
the coverage of significant accounts tested for the group. Of the 41 specific scope components, we instructed 10 of these locations to perform
specified procedures over impairment of goodwill and other intangible assets, recoverability of certain receivables and the carrying value of
certain investments held by the group.

The remaining components not subject to full or specific group scoping are not significant individually or in the aggregate. They include many
small, low risk components and balances; each remaining component represents an average of 0.11% of the total group loss before tax and
0.11% of total group revenue. For these components, we performed other procedures, including evaluating and testing management’s group
wide controls across a range of geographies and segments, specifically testing the oversight and review controls that management has in place
to ensure there are no material misstatements in these locations. We performed analytical and enquiry procedures to address the risk of residual
misstatement on a segment-wide and component basis. We tested consolidation journals to identify the existence of any further risks of
misstatement that could have been material to the group financial statements.

Involvement with component teams
In establishing our overall approach to the group audit, we determined the type of work that needed to be undertaken at each of the
components by us, as the primary audit engagement team, or by component auditors from other EY global network firms operating under our
instruction. Of the 9 full scope components, audit procedures were performed on 5 of these directly by the primary audit engagement team. For
the 41 specific scope components, audit procedures were performed on 25 of these directly by the primary audit engagement team. Testing of
management’s group wide controls was performed by component auditors. Where work was performed by component auditors, we
determined the appropriate level of involvement to enable us to determine that sufficient audit evidence had been obtained as a basis for our
opinion on the group as a whole.

The group audit team continued to follow a programme of planned visits designed to ensure that the Senior Statutory Auditor or his designate
visits 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. During the current year’s audit cycle, visits were undertaken by the primary audit engagement team to the
component teams in Germany, India, Russia, Singapore, Trinidad and the US. Part of the purpose of these visits is to confirm that appropriate
procedures have been performed by the auditors of the components and that the significant audit areas were covered as communicated in the
detailed audit instructions, including the risks of material misstatement as outlined above. The primary audit engagement team review included
examining key working papers and conclusions where these related to areas of management and auditor judgement with specific focus on the
risks detailed above. The primary audit engagement team also participated in the component teams’ planning, during visits made earlier in the
audit period. Telephone and video meetings were held with the auditors at locations which the primary audit engagement team did not visit in
person. This, together with additional procedures performed at group level, gave us appropriate evidence for our opinion on the group financial
statements.

One of the significant locations is Russia, which includes Rosneft, a material associate not controlled by BP. We were provided with appropriate
access to Rosneft’s auditor 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.

Our application of materiality
We apply the concept of materiality in planning and performing the audit, in evaluating the effect of identified misstatements on the audit and in
forming our audit opinion.

Materiality
The magnitude of an omission or misstatement that, individually or in the aggregate, could reasonably be expected to influence the economic
decisions of the users of the financial statements. Materiality provides a basis for determining the nature and extent of our audit procedures.

We determined materiality for the group to be $0.5 billion (2015 $0.5 billion). For our current year audit we changed the basis of determining
materiality from current year underlying replacement cost profit before interest and taxation (as defined on page 284) that was used in 2015. In
setting audit materiality for the current year we considered the activity levels within the business and the fact that the commodity prices
experienced in the current period are below those expected in the coming years by the group and the wider market. We believe it is appropriate
in these circumstances to determine materiality based on 5% of the average 2016 underlying replacement cost profit before interest and
taxation and how those results would look if the oil and gas prices forecast by the company for 2017 and 2018 had prevailed in the year. These
forward earnings have been determined using BP’s Rules of Thumb, available on the website, applied to the 2016 actual results as the base
year.

Underlying replacement cost profit before interest and taxation remains the most appropriate measure upon which to calculate materiality, due
to the fact it excludes the impact of changes in crude oil, gas and product prices and items disclosed as non-operating items, which can
significantly distort the group’s results in a given period. For details of non-operating items please see page 241 of the Annual Report and
Form 20-F 2016.

During the course of our audit, we re-assessed initial materiality in the context of the group’s performance and forward expectations and this
resulted in no change from our original assessment of materiality.

Performance materiality
The application of materiality at the individual account or balance level. It is set at an amount to reduce to an appropriately low level the
probability that the aggregate of uncorrected and undetected misstatements exceeds materiality.

On the basis of our risk assessments, together with our assessment of the group’s overall control environment, our judgement was that
performance materiality was 75% (2015 75%) of our materiality, namely $375 million (2015 $375 million). We have set performance materiality
at this percentage to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements
exceeds materiality.

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Audit work at component locations for the purpose of obtaining audit coverage over significant financial statement accounts is undertaken based
on a percentage of total performance materiality. The performance materiality set for each component is based on the relative scale and risk of
the component to the group as a whole and our assessment of the risk of misstatement at that component. In the current year, the range of
performance materiality allocated to components was $75 million to $281 million (2015 $75 million to $300 million).

Reporting threshold
An amount below which identified misstatements are considered as being clearly trivial.

We agreed with the audit committee that we would report to them all uncorrected audit differences in excess of $25 million (2015 $25 million),
which is set at 5% of materiality, as well as differences below that threshold that, in our view, warranted reporting on qualitative grounds.

We evaluate any uncorrected misstatements against both the quantitative measures of materiality discussed above and in light of other relevant
qualitative considerations in forming our opinion.

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 the parent company’s circumstances and have been consistently applied and adequately
disclosed; the reasonableness of significant accounting estimates made by the directors; and the overall presentation of the financial
statements. In addition, we read all the financial and non-financial information in the Annual Report 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.

Respective responsibilities of directors and auditor
As explained more fully in the Statement of directors’ responsibilities set out on page 111, 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.

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.

Opinion on other matters prescribed by the Companies Act 2006
In our opinion:

• the part of the Directors’ remuneration report to be audited has been properly prepared in accordance with the Companies Act 2006; and
• based on the work undertaken in the course of the audit:

• 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.

• The Strategic report and the Director’s report have been prepared in accordance with applicable legal requirements.

Matters on which we are required to report by exception

ISAs (UK and Ireland) reporting

We are required to report to you if, in our opinion, financial and non-
financial information in the annual report is:

• materially inconsistent with the information in the audited financial

We have no
exceptions to
report.

statements; or

• apparently materially incorrect based on, or materially inconsistent

with, our knowledge of the group acquired in the course of
performing our audit; or

• otherwise misleading.

In particular, we are required to report whether we have identified
any inconsistencies between our knowledge acquired in the course
of performing the audit and the directors’ statement that they
consider the annual report and accounts taken as a whole is fair,
balanced and understandable and provides the information necessary
for shareholders to assess the entity’s position and performance,
business model and strategy; and whether the annual report
appropriately addresses those matters that we communicated to the
audit committee that we consider should have been disclosed.

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Companies Act 2006 reporting

In light of our knowledge and understanding of the Company and its
environment obtained in the course of the audit, we have identified
no material misstatements in the Strategic Report or Directors’
Report.

We have no
exceptions to
report.

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.

Listing Rules review requirements

We are required to review:

• the directors’ statement in relation to going concern, set out on
page 112, and longer-term viability, set out on page 112; and
• the part of the Corporate governance statement relating to the
company’s compliance with the provisions of the UK Corporate
Governance Code specified for our review.

We have no
exceptions to
report.

Statement on the directors’ assessment of the principal risks that would threaten the solvency or liquidity of the entity

ISAs (UK and Ireland) reporting

We have nothing
material to add or
to draw attention
to.

We are required to give a statement as to whether we have anything
material to add or to draw attention to in relation to:

• the directors’ confirmation in the annual report that they have

carried out a robust assessment of the principal risks facing the
entity, including those that would threaten its business model,
future performance, solvency or liquidity;

• the disclosures in the annual report that describe those risks and

explain how they are being managed or mitigated;

• the directors’ statement in the Directors’ report (Directors’
statements, page 112) about whether they considered it
appropriate to adopt the going concern basis of accounting in
preparing them, and their identification of any material
uncertainties to the entity’s ability to continue to do so over a
period of at least twelve months from the date of approval of the
financial statements; and

• the directors’ explanation in the annual report as to how they have
assessed the prospects of the entity, over what period they have
done so and why they consider that period to be appropriate, and
their statement as to whether they have a reasonable expectation
that the entity will be able to continue in operation and meet its
liabilities as they fall due over the period of their assessment,
including any related disclosures drawing attention to any
necessary qualifications or assumptions.

John C. Flaherty (Senior Statutory Auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
6 April 2017

The maintenance and integrity of the BP p.l.c. web site 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 web site.
Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

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Consolidated financial statements of the BP group

Report of Independent Registered Public Accounting Firm
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 2016 and 31 December 2015, 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 2016. 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 2016 and 31 December 2015 and the group results of its operations and its cash flows for each of the three years in the period
ended 31 December 2016, 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.

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 2016, based on criteria established in the UK Financial Reporting Council’s Guidance on Risk
Management, Internal Control and Related Financial and Business Reporting and our report dated 6 April 2017 expressed an unqualified opinion.

/s/ Ernst & Young LLP
London, United Kingdom
6 April 2017

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Consolidated financial statements of the BP group

Report of Independent Registered Public Accounting Firm
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 2016, based on criteria established in the UK Financial
Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting. 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 over financial reporting on page 267. 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 2016, based on
the UK Financial Reporting Council’s 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 2016 and 2015, 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 2016, and
our report dated 6 April 2017 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP
London, United Kingdom
6 April 2017

Consent of independent registered public accounting firm

We consent to the incorporation by reference of our reports dated 6 April 2017, 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 2016 in the following Registration Statements:

Registration Statement on Form F-3 (File Nos. 333-208478 and 333-208478-01) of BP Capital Markets p.l.c. and BP p.l.c.; and Registration
Statements on Form S-8 (File Nos. 333-67206, 333-79399, 333-103924, 333-123482, 333-123483, 333-131583, 333-131584, 333-132619,
333-146868, 333-146870, 333-146873, 333-173136, 333-177423, 333-179406, 333-186462, 333-186463, 333-199015, 333-200794, 333-
200795, 333-207188, 333-207189, 333-210316 and 333-210318) of BP p.l.c.

/s/ Ernst & Young LLP
London, United Kingdom
6 April 2017

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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

Profit (loss) before interest and taxation
Finance costsa
Net finance expense relating to pensions and other post-retirement benefits

Profit (loss) before taxation
Taxationa

Profit (loss) for the year

Attributable to

BP shareholders
Non-controlling interests

Earnings per share – cents
Profit (loss) for the year attributable to BP shareholders

Basic
Diluted

Per ADS (dollars)

Basic
Diluted

a See Note 2 for information on the impact of the Gulf of Mexico oil spill on these income statement line items.

Note

2016

2015

5
15
16
6
4

5
5
4
7

6
23

10
10

183,008
966
994
506
1,132

186,606
132,219
29,077
683
14,505
(1,664)
1,721
10,495

(430)
1,675
190

(2,295)
(2,467)

172

115
57

172

0.61
0.60

0.04
0.04

222,894
(28)
1,839
611
666

225,982
164,790
37,040
1,036
15,219
1,909
2,353
11,553

(7,918)
1,347
306

(9,571)
(3,171)

(6,400)

(6,482)
82

(6,400)

(35.39)
(35.39)

(2.12)
(2.12)

$ million

2014

353,568
570
2,802
843
895

358,678
281,907
27,375
2,958
15,163
8,965
3,632
12,266

6,412
1,148
314

4,950
947

4,003

3,780
223

4,003

20.55
20.42

1.23
1.23

122

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Group statement of comprehensive incomea
For the year ended 31 December

Profit (loss) for the year
Other comprehensive income
Items that may be reclassified subsequently to profit or loss

Note

2016
172

2015
(6,400)

$ million

2014
4,003

Currency translation differences
Exchange gains (losses) on translation of foreign operations reclassified to gain or loss on

254

(4,119)

(6,838)

sale of businesses and fixed assets

Available-for-sale investments
Cash flow hedges marked to market
Cash flow hedges reclassified to the income statement
Cash flow hedges reclassified to the balance sheet
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that may be reclassified

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset
Share of items relating to equity-accounted entities, net of tax
Income tax relating to items that will not be reclassified

Other comprehensive income

Total comprehensive income

Attributable to

BP shareholders
Non-controlling interests

a See Note 31 for further information.

Group statement of changes in equitya

29
29
29

30
1
(639)
196
81
833
13
769

(2,496)
–
739
(1,757)

(988)

(816)

(846)
30
(816)

23
1
(178)
249
22
(814)
257
(4,559)

4,139
(1)
(1,397)
2,741

51
–
(155)
(73)
(11)
(2,584)
147
(9,463)

(4,590)
4
1,334
(3,252)

(1,818)

(12,715)

(8,218)

(8,712)

(8,259)
41
(8,218)

(8,903)
191
(8,712)

At 1 January 2016
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
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 2016

At 1 January 2015
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
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 2015

At 1 January 2014
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
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

a See Note 31 for further information.
b See Note 9 for further information.

Share
capital
and
capital
Treasury
reserves
shares
43,902 (19,964)
–
–
–
–
1,521

–
–
–
–
2,220

Foreign
currency
translation
reserve
(7,267)
–
389
389
–
–

Fair
value
reserves

Profit and
loss
account
(823) 81,368
115
(1,020)
(905)
(4,611)
(750)

–
(330)
(330)
–
–

–
–

–
–
46,122 (18,443)

43,902 (20,719)
–
–
–
–
755

–
–
–
–
–

–
–

–
–
43,902 (19,964)

43,656 (20,971)
–
–
–
–
–
252

–
–
–
–
–
246

–
–

–
–
43,902 (20,719)

–
–

106
430
(6,878) (1,153) 75,638

–
–

(3,409)
–
(3,858)
(3,858)
–
–

–
–
(7,267)

3,525
–
(6,934)
(6,934)
–
–
–

–
–
(3,409)

(897) 92,564
(6,482)
2,007
(4,475)
(6,659)
(99)

–
74
74
–
–

–
–

40
(3)
(823) 81,368

(695) 103,787
3,780
(5,547)
(1,767)
(5,850)
(3,366)
(313)

–
(202)
(202)
–
–
–

–
–

73
–
(897) 92,564

BP
shareholders’
equity
97,216
115
(961)
(846)
(4,611)
2,991

Non-
controlling
interests
1,171
57
(27)
30
(107)
–

106
430
95,286

111,441
(6,482)
(1,777)
(8,259)
(6,659)
656

40
(3)
97,216

129,302
3,780
(12,683)
(8,903)
(5,850)
(3,366)
185

73
–
111,441

–
463
1,557

1,201
82
(41)
41
(91)
–

–
20
1,171

1,105
223
(32)
191
(255)
–
–

–
160
1,201

$ million

Total
equity
98,387
172
(988)
(816)
(4,718)
2,991

106
893
96,843

112,642
(6,400)
(1,818)
(8,218)
(6,750)
656

40
17
98,387

130,407
4,003
(12,715)
(8,712)
(6,105)
(3,366)
185

73
160
112,642

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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

Assets classified as held for sale

Total assets

Current liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions

Liabilities directly associated with assets classified as held for sale

Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits

Total liabilities

Net assets

Equity

BP shareholders’ equity
Non-controlling interests

Total equity

C-H Svanberg Chairman
R W Dudley Group Chief Executive
6 April 2017

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Note

2016

$ million

2015

129,758
11,627
18,660
8,412
9,422
1,002

178,881
529
2,216
4,409
1,003
1,545
2,647

129,757
11,194
18,183
8,609
14,092
1,033

182,868
532
1,474
4,359
945
4,741
584

195,503

191,230

259
17,655
20,675
3,016
1,486
1,194
44
23,484

67,813
–

272
14,142
22,323
4,242
1,838
599
219
26,389

70,024
578

67,813

70,602

263,316

261,832

37,915
2,991
5,136
6,634
1,666
4,012

58,354
–

31,949
3,239
6,261
6,944
1,080
5,154

54,627
97

58,354

54,724

13,946
5,513
469
51,666
7,238
20,412
8,875

2,910
4,283
890
46,224
9,599
35,960
8,855

108,119

108,721

166,473

163,445

96,843

98,387

95,286
1,557

96,843

97,216
1,171

98,387

11
13
14
15
16
17

19
29

8
23

18
19
29

17
24

21
29

25
8
22
23

31
31

Group cash flow statement
For the year ended 31 December

Operating activities

Profit (loss) before taxation

Adjustments to reconcile profit (loss) 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 provided by (used in) financing activities

Currency translation differences relating to cash and cash equivalents

Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year

Cash and cash equivalents at end of year

Note

2016

2015

$ million

2014

(2,295)

(9,571)

4,950

7
5
4

4
4

1,274
14,505
(2,796)
(1,960)
1,105
(200)
267
1,675
(1,137)
190
779

(467)
4,487
(3,681)
(1,172)
1,655
(1,538)

10,691

1,829
15,219
1,243
(1,811)
1,614
(247)
176
1,347
(1,080)
306
321

(592)
11,792
3,375
6,796
(9,328)
(2,256)

19,133

(16,701)
(1)
(50)
(700)
1,372
1,259
68

(18,648)
23
(265)
(1,312)
1,066
1,726
110

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

(14,753)

(17,300)

(19,574)

–
12,442
(6,685)
51
887

(4,611)
(107)

1,977

(820)

(2,905)
26,389

23,484

–
8,173
(6,426)
473
(5)

(6,659)
(91)

(4,535)

(672)

(3,374)
29,763

26,389

(4,589)
12,394
(6,282)
(693)
9

(5,850)
(255)

(5,266)

(671)

7,243
22,520

29,763

BP Annual Report and Form 20-F 2016

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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 2016 were approved and signed by the group chief
executive and chairman on 6 April 2017 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. 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 on a going concern basis and in accordance with IFRS and IFRS Interpretations
Committee (IFRIC) interpretations issued and effective for the year ended 31 December 2016. 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, the disclosure of contingent assets and
liabilities, and the reported amounts of revenues and expenses. 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, including trade receivables; derivative financial
instruments, including the application of hedge accounting; provisions and contingencies, including provisions and contingencies related to the
Gulf of Mexico oil spill; pensions and other post-retirement benefits; and income taxes.

Basis of consolidation
The group financial statements consolidate the financial statements of BP p.l.c. and 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 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 recognized at
their fair values at the acquisition date.

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. See Note 13 for further information.

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. Any 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 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 classified as an associate.

Since 21 March 2013, BP has owned 19.75% of the voting shares of Rosneft Oil Company (Rosneft), a Russian oil and gas company. The
Russian federal government, through its investment company JSC Rosneftegaz, owned 50% plus one share of the voting shares of Rosneft
at 31 December 2016. 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

126

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1. Significant accounting policies, judgements, estimates and assumptions – continued

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 a
member of the board of directors of Rosneft since 2013 and he is a member of the Rosneft board’s Strategic Planning Committee. A second
BP-nominated director, Guillermo Quintero, has been a member of the Rosneft board and its HR and Remuneration Committee since 2015.
BP also 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, classified
as an associate and accounted for using the equity method. 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.

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.

Segmental reporting
The group’s operating segments are established on the basis of those components of the group that are evaluated regularly by the group chief
executive, BP’s 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 5.

Foreign currency translation
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of
those entities at the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are
retranslated into the functional currency at the spot exchange rate on 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, associates,
and related goodwill, are translated into US dollars at the spot exchange rate on 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 recognized in a separate component of
equity and reported in other 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 reported in other comprehensive income. On disposal or partial disposal of a
non-US dollar functional currency subsidiary, joint venture or associate, the related accumulated exchange gains and losses recognized in
equity are reclassified from equity 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, and actions required to complete the plan of sale should indicate that it is unlikely that significant changes to the plan will be made
or that the plan will be withdrawn.

Property, plant and equipment and intangible assets are not depreciated or amortized once classified as held for sale.

Intangible assets
Intangible assets, other than goodwill, include expenditure on the exploration for and evaluation of oil and natural gas resources, computer
software, patents, licences and trademarks and are stated at the amount initially recognized, less accumulated amortization and accumulated
impairment losses.

Intangible assets acquired separately from a business are carried initially at cost. 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.

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Intangible assets with a finite life, other than capitalized exploration and appraisal costs as described below, are amortized on a straight-line basis
over their expected useful lives. For patents, licences and trademarks, expected useful life is the shorter of the duration of the legal agreement
and economic useful life, and can range from three to 15 years. Computer software costs generally have a useful life of three to five years.

The expected useful lives of assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

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 as described below.

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 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 recognized as an expense 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 costs are written off. 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. If it is determined that development will not occur
then the costs are expensed.

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 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 of 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 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

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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 judgements and estimates: estimation of oil and natural gas reserves
Significant technical and commercial judgements are required to determine the group’s estimated oil and natural gas reserves. Reserves
estimates 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 187, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes
are provided on page 252.

Estimates of oil and natural gas reserves determined by applying US Securities and Exchange Commission regulations 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 estimates also have a direct impact on the assessment of the recoverability of asset carrying values reported in the financial
statements. If proved reserves estimates determined by applying management’s assumptions are revised downwards, earnings could be
affected by changes in depreciation expense or an immediate write-down of the property’s carrying value.

The 2016 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 187. 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 11 and Note 5 respectively.

Impairment of property, plant and equipment, intangible assets, and goodwill
The group assesses assets or groups of assets, called cash-generating units (CGUs), for impairment whenever events or changes in circumstances
indicate that the carrying amount of an asset or CGU may not be recoverable; for example, changes in the group’s business plans, changes in the
group’s assumptions about commodity prices, 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 or CGU’s recoverable amount. Individual assets are grouped into CGUs 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. A CGU’s recoverable amount is the higher of its fair value less costs of disposal and its value in use. Where the carrying
amount of a CGU exceeds its recoverable amount, the CGU 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 assumptions regarding market conditions, such as oil prices, natural gas prices, refining margins, refined product margins and cost
inflation rates are set by senior management. These 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 group 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 the lower of its recoverable amount and the carrying amount that
would have been determined, net of depreciation, had no impairment loss been recognized for the asset in prior years. Impairment reversals are
recognized in profit or loss. After 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.

Goodwill is reviewed for impairment annually or more frequently if events or changes in circumstances indicate the recoverable amount of the
group of CGUs to which the goodwill relates should be assessed. In assessing whether goodwill has been impaired, the carrying amount of the
group of CGUs to which goodwill has been allocated is compared with its recoverable amount. Where the recoverable amount of the group of

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CGUs is less than the carrying amount (including goodwill), an impairment loss is recognized. An impairment loss recognized for goodwill is not
reversed in a subsequent period.

Significant judgements and estimates: recoverability of asset carrying values
Determination as to whether, and by how much, an asset, CGU, or group of CGUs containing goodwill is impaired involves management
estimates on highly uncertain matters such as the effects of inflation and deflation on operating expenses, discount rates, production profiles,
reserves and resources, and future commodity prices, including the outlook for global or regional market supply-and-demand conditions for
crude oil, natural gas and refined products. Judgement is required when determining the appropriate grouping of assets into a CGU or the
appropriate grouping of CGUs for impairment testing purposes. See Note 13 for details on how these groupings have been determined in
relation to the impairment testing of goodwill.

As disclosed above, the recoverable amount of an asset is the higher of its value in use and its fair value less costs of disposal. 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 the asset, CGU or
group of CGUs containing goodwill and the test is performed on a post-tax basis.

Irrespective of whether there is any indication of impairment, BP is required to test annually for impairment of goodwill acquired in business
combinations. The group carries goodwill of approximately $11.2 billion on its balance sheet (2015 $11.6 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 for an extended period, the group may need to
recognize goodwill impairment charges.

Details of impairment charges and reversals recognized in the income statement are provided in Note 4 and details on the carrying amounts
of assets are shown in Note 11, Note 13 and Note 14.

Specific judgements and estimates made in impairment tests in 2016 relating to discount rates, oil and gas properties and oil and gas prices
are discussed below.

Discount rates
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 pre-tax discount rate is based upon the cost of funding the group derived from an established model, adjusted to a pre-tax
basis. Fair value less costs of disposal calculations use the post-tax discount rate.

The discount rates applied in impairment tests are reassessed each year. In 2016 the discount rate used to determine recoverable amounts
based on fair value less costs of disposal was revised to 6% (2015 7%). The discount rate used to determine recoverable amounts based on
value in use was revised to 9% (2015 11%). In both cases, where the cash-generating unit is located in a country which is judged to be higher
risk an additional 2% premium was added to the discount rate (2015 2%).

Oil and natural gas properties
For oil and natural gas properties, expected future cash flows are estimated using management’s best estimate of future oil and natural gas
prices and production 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.

Reserves assumptions for value-in-use tests are restricted to proved and probable reserves.

When estimating the fair value of our Upstream assets, assumptions reflect all reserves and resources that a market participant would
consider when valuing the asset, which in some cases are broader in scope than the reserves used in a value-in-use test. In determining a fair
value, risk factors may be applied to reserves and resources which do not meet the criteria to be treated as proved. Depending upon the
classification of the reserves and resources, this can result in associated forecast cash flows being reduced by a factor of between 10% and
90% from their estimated full potential value. Changing the risk factor applied will in some cases have an impact upon the carrying value of
the asset concerned. A 10% increase in the risk factors used in any single test could have an impact of up to $0.4 billion upon the carrying
value of that asset.

The recoverability of intangible exploration and appraisal expenditure is covered under Oil and natural gas exploration, appraisal and
development expenditure above.

Oil and gas prices
During the third quarter of 2016, the price assumptions used in impairment tests were revised.

The long-term price assumptions used to determine recoverable amount based on fair value less costs of disposal from 2022 onwards are
derived from $75 per barrel for Brent and $4/mmBtu for Henry Hub (both in 2015 prices) inflated for the remaining life of the asset. For 2015
the equivalent values were $80 per barrel for Brent and $5/mmBtu for Henry Hub. To determine recoverable amount based on value in use,
the price assumptions were inflated to 2022 but from 2022 onwards were not inflated.

For both value-in-use and fair value less costs of disposal impairment tests, the price assumptions used for the five-year period to 2021 have
been set such that there is a gradual transition from current market prices to the long-term price assumptions as noted above. For 2015,
market prices were used for the first five years ranging from $40 per barrel for Brent and $2.38/mmBtu for Henry Hub in 2016 to $56 per barrel for
Brent and $3.18/mmBtu in 2020. Prices used this year were revised due to a lack of liquidity in the market beyond the very near term.

Current market prices for oil reflect the elevated level of oil stocks following strong growth in US shale and OPEC production volumes in
recent years. US production fell during 2016 in response to lower prices and, towards the end of the year, OPEC and a number of non-OPEC
countries announced an agreement to reduce production volumes. BP’s long-term assumption for oil is higher than current market prices
because prices are expected to increase as the current record level of oil inventories is gradually unwound, underpinned by solid demand
growth and muted increases in supply.

US gas prices have fallen back recently in response to the unusually mild winter. BP’s long-term price assumption for US gas is higher than
current market prices because we expect demand for US gas to grow with increased exports of liquefied natural gas (LNG), underpinned by
strong growth in the global demand for gas. We expect natural gas to be the fastest growing fossil fuel over the next 20 years, supported by
increasing environmental regulation encouraging a switch from coal to cleaner, lower carbon fuels including gas, as well as renewables.

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Inventories
Inventories, other than inventories held for short-term 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 short-term 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 the lower of cost on a weighted average basis and net realizable value.

Leases
Agreements under which payments are made to owners in return for the right to use an asset are accounted for as leases. Leases that transfer
substantially all the risks and rewards of ownership are recognized as finance leases. All other leases are accounted for as operating 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 on a straight-line basis over the lease term.

Financial assets
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 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 generally 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
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, interest recognized using the effective interest
method, 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 judgement: recoverability of trade receivables
Judgements are required in assessing the recoverability of overdue trade receivables and determining whether a provision against 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 28 for information on overdue receivables.

Financial liabilities
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, net of transaction costs. 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 in interest and other income and finance costs respectively.

This category of financial liabilities includes trade and other payables and finance debt, except finance debt designated in a fair value hedge
relationship.

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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 recognized initially at fair value on the date on
which a derivative contract is entered into and 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 (for example, oil, oil products, gas or power) that can be settled net in cash, 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. Contracts to buy or
sell LNG are not accounted for as derivatives as they are not considered capable of being settled net in cash.

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 gain 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 subsequent to the initial valuation are recognized immediately in 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 and certain currency risks 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 reported in other comprehensive income, while the ineffective
portion is recognized in profit or loss. Amounts reported in 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 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. See Note 28 and Note 29 for further information.

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.

Significant estimate: 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. 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 available active market pricing data and
modelled using the maximum available external pricing information. Additionally, where limited data exists for certain products, prices are
determined using historic and long-term pricing relationships. Price volatility is also an input for options models.

Changes in the key assumptions could have a material impact on the fair value gains and losses on derivatives recognized in the income
statement. For more information see Note 29.

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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 and contingencies
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% (2015 2.75%) or a
real discount rate of 0.5% (2015 0.75%), 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.

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 18 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. 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 judgements and estimates: provisions
During 2016, significant progress was made in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill for
which, at 31 December 2015, no reliable estimate could be made. As a result, a judgement has been made that a reliable estimate can now be
made for all remaining material liabilities arising from the incident. Consequently, the group’s provision at 31 December 2016 for costs associated
with the incident now includes the estimated cost of resolving all outstanding business economic loss claims under the Plaintiffs’ Steering
Committee (PSC) settlement and the cost of resolving economic loss and property damage claims from individuals and businesses that opted out
of the PSC settlement and/or were excluded from that settlement. The provision for outstanding business economic loss claims under the PSC
settlement was determined based upon an expected value of the remaining claims and the resultant charge was recognized in the income
statement. Claims are determined by the Deepwater Horizon Court Supervised Settlement Program in accordance with the PSC settlement
agreement and, in addition, certain claims are settled by BP. The amounts ultimately payable may differ from the amount provided and the timing
of payment is uncertain. A significant number of claims determined by the DHCSSP have been and may be appealed by BP and/or the claimants.
Depending upon the resolution of these claims, the amount payable may differ from what is currently provided for.

Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group’s financial performance.

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. 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.

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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 2016 was a real rate of 0.5% (2015 0.75%), 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 22. As further described in Note 32, the group is subject to claims and actions. The facts and circumstances
relating to particular cases are evaluated regularly in determining whether a provision relating to a specific litigation should be recognized 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 of the equity instruments on the date on
which they 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.

For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are
measured at the fair value of the goods or services received unless their fair value cannot be reliably estimated. If the fair value of the goods and
services received cannot be reliably estimated, the transaction is measured by reference to the fair value of the equity instruments granted.

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.

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 recognized on the balance sheet for each plan comprises the difference between the present
value of the defined benefit obligation (using a discount rate based on high quality corporate bonds) and 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, typically by way of refund.

Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.

Significant estimate: pensions and other post-retirement benefits
Accounting for defined benefit pensions and other post-retirement benefits involves making significant estimates about uncertain events,
including 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.

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1. Significant accounting policies, judgements, estimates and assumptions – continued

Assumptions about these variables 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 23.

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 23.

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 applicable 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 23.

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 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
• 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

• 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 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.

Significant judgements and estimates: 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 and
estimates are required to be made of the amount of future taxable profits that will be available.

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 8.

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.

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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:

• Customs duties or sales taxes incurred on the purchase of goods and services which are not recoverable from the taxation authority are

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 – treasury shares
The group’s holdings in its own equity instruments are shown as deductions from shareholders’ equity at cost. 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. 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 short-term 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.

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.

IFRS 9 ‘Financial Instruments’ 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 of
financial assets and hedge accounting.

IFRS 15 ‘Revenue from Contracts with Customers’ provides a single model for accounting for revenue arising from contracts with customers,
focusing on the identification and satisfaction of performance obligations, and is effective for annual periods beginning on or after 1 January
2018. IFRS 15 will supersede IAS 18 ‘Revenue’.

BP expects to adopt IFRS 9 and IFRS 15 on 1 January 2018. The group’s evaluation of the effect of adoption of these standards is ongoing but it
is not currently anticipated that either IFRS 9 or IFRS 15 will have a material effect on the financial statements.

The EU has adopted both IFRS 9 and IFRS 15.

IFRS 16 ‘Leases’ provides a new model for lessee accounting in which all leases, other than short-term and small-ticket-item leases, will be
accounted for by the recognition on the balance sheet of a right-to-use asset and a lease liability, and the subsequent amortization of the right-to-
use asset over the lease term. IFRS 16 will be effective for annual periods beginning on or after 1 January 2019.

BP expects to adopt IFRS 16 on 1 January 2019 using the modified retrospective approach to transition permitted by the standard in which the
cumulative effect of initially applying the standard is recognized in opening retained earnings at the date of initial application. The group’s
evaluation of the effect of adoption of the standard is ongoing but it is expected that it will have a material effect on the group’s financial
statements, significantly increasing the group’s recognized assets and liabilities. It is expected that the presentation and timing of recognition of
charges in the income statement will also change as the operating lease expense currently reported under IAS 17, typically on a straight-line
basis, will be replaced by depreciation of the right-to-use asset and interest on the lease liability. Information on the group’s leases currently
classified as operating leases, which are not recognized on the balance sheet, is provided in Note 27.

The EU has not yet adopted IFRS 16.

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.

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. Following significant progress in resolving outstanding claims arising from the 2010 Deepwater Horizon accident and oil spill, a reliable
estimate has now been determined for all remaining material liabilities arising from the incident.

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2. Significant event – Gulf of Mexico oil spill – continued

The cumulative pre-tax income statement charge since the incident amounts to $62.6 billion. For more information on the types of expenditure
included in the cumulative income statement charge, see Impact upon the group income statement below. It is now possible to reliably estimate
the cost of resolving outstanding business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement and the cost of
resolving economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were
excluded from that settlement. The pre-tax income statement charge for the year of $7.1 billion is primarily attributable to the recognition of
additional provisions for these claims.

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
Accruals
Provisions

Net current assets (liabilities)

Non-current assets
Deferred tax

Non-current liabilities
Other payables
Accruals
Provisions
Deferred tax

Net non-current assets (liabilities)

Net assets (liabilities)

Cash flow statement
Profit (loss) before taxation
Net charge for interest and other finance expense, less net interest paid
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

$ million

2014

781

(781)
38

(819)
262

(557)

2016

2015

6,640

11,709

(6,640)
494

(7,134)
3,105

(4,029)

(11,709)
247

(11,956)
3,492

(8,464)

194

686

(3,056)
–
(2,330)

(5,192)

(693)
(40)
(3,076)

(3,123)

2,973

–

(13,522)
–
(112)
5,119

(2,057)
(186)
(13,431)
5,200

(5,542)

(10,474)

(10,734)

(13,597)

(7,134)
494
4,353
(3,210)
(1,608)

(7,105)

(11,956)
247
11,296
–
(732)

(819)
38
939
(662)
(792)

(1,145)

(1,296)

The impact on net cash provided by operating activities, on a post-tax basis, amounted to an outflow of $6,892 million (2015 outflow of
$1,130 million and 2014 outflow of $9 million).

Trust fund
BP established the Deepwater Horizon Oil Spill Trust (the Trust), 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. 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. During 2014, cumulative charges to be paid by the Trust reached $20 billion. Subsequent additional costs, over and above
those provided within the $20 billion, are expensed to the income statement as incurred. During the first half of 2016, the remaining cash in the
Trust was exhausted and BP commenced paying claims and other costs previously funded from the Trust. For certain costs, these payments are
made by BP into qualified settlement funds administered by the PSC settlement programmes, which then distribute the amounts to claimants.
During 2016, BP paid $3,210 million to the qualified settlement funds.

Other payables
Other payables include amounts payable under the agreements with the United States and five Gulf coast states that were approved by the
federal district court in 2016, including amounts payable for natural resource damages, state claims and Clean Water Act penalties (for full details

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of these agreements, see BP Annual Report and Form 20-F 2015). Further, at 31 December 2016, $1,929 million remains in Other payables in
relation to the 2012 agreement with the US government to resolve all federal criminal claims arising from the incident, of which $739 million falls
due in 2017. In addition, Other payables at 31 December 2016 includes BP’s remaining 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. Amounts payable for certain economic loss and property damage claims from individuals and businesses that either opted out of the
PSC settlement and/or were excluded from that settlement, as well as certain business economic loss claims under the PSC settlement, are
also included in Other payables.

Provisions and contingent liabilities
Provisions
Provisions relating to the agreements with the United States and five Gulf coast states were reclassified to Other payables during 2016, upon
approval of those agreements by the federal district court. Remaining provisions relating to the Gulf of Mexico oil spill relate to litigation and
claims.

Movements in each class of provision during the year and cumulatively since the incident are presented in the tables below.

At 1 January
Net increase in provision
Unwinding of discount
Reclassified to other payables
Utilization – paid by BP

– paid by the settlement fund or Trust

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 settlement fund or Trust

At 31 December 2016

Environmental

Litigation
and claims

Clean Water
Act

5,919
–
52
(5,970)
(1)
–

–

–
–

6,459
6,440
25
(4,943)
(2,086)
(3,453)

2,442

2,330
112

4,129
–
38
(4,167)
–
–

–

–
–

$ million

2016

Total

16,507
6,440
115
(15,080)
(2,087)
(3,453)

2,442

2,330
112

$ million

Cumulative since the incident

Environmental

Litigation
and claims

Clean Water
Act

19,992
159
(130)
(6,429)
(11,711)
(1,881)

38,867
81
(74)
(9,351)
(6,400)
(20,681)

4,171
106
(110)
(4,167)
–
–

Total

63,030
346
(314)
(19,947)
(18,111)
(22,562)

–

2,442

–

2,442

Environmental
The environmental provisions relating to natural resource damage costs and the early restoration framework agreement were reclassified to
Other payables during 2016 following approval by the Court in April 2016 of the Consent Decree between the United States, the Gulf states and
BP.

Litigation and claims
The litigation and claims provision includes amounts for the future cost of resolving 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. Claims administration costs
and legal costs have also been provided for.

Litigation and claims – PSC settlement
The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the PSC provides for a court-supervised
settlement programme, the Deepwater Horizon Court Supervised Settlement Program (DHCSSP), which commenced operation on 4 June 2012.
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 261. The provision for the cost associated with the
2012 PSC settlement has been determined based upon an expected value of the remaining claims, including business economic loss claims.
During the year, significant progress was made in resolving business economic loss claims. Claims were determined by the DHCSSP in
accordance with the PSC settlement agreement and in addition, certain claims were settled by BP. The provision has been increased in the year
to reflect the estimate of the cost of the remaining claims which are expected to be determined and paid by the DHCSSP or resolved by BP, and
associated costs. Amounts to resolve remaining claims are expected to be substantially paid in 2017. However, the amounts ultimately payable
may differ from the amount provided and the timing of payment is uncertain. A significant number of claims determined by the DHCSSP have
been and may be appealed by BP and/or the claimants. Depending upon the resolution of these claims, the amount payable may differ from
what is currently provided for.

Litigation and claims – Other claims
An estimate of the cost of the remaining economic loss and property damage claims from individuals and businesses that either opted out of the
PSC settlement and/or were excluded from that settlement, is recognized in provisions. Amounts have been reclassified to Other payables
during the year where settlements were agreed.

The 31 December 2015 provision recognized for litigation and claims included amounts agreed under the agreements with the United States and
five Gulf Coast states in relation to state claims, which were reclassified to Other payables during 2016. These state claims are payable over 18
years.

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2. Significant event – Gulf of Mexico oil spill – continued

Clean Water Act penalties
The provision previously recognized for penalties under Section 311 of the Clean Water Act, as determined by the civil settlement with the
United States, was reclassified to Other payables during 2016 following approval by the Court of the Consent Decree. The amount is payable in
instalments over 15 years, commencing April 2017. The unpaid balance of this penalty accrues interest at a fixed rate.

Provision movements
The total amount recognized as an increase in provisions during the year was $6,440 million. It is now possible to reliably estimate the cost of
resolving outstanding business economic loss claims under the Plaintiffs’ Steering Committee (PSC) settlement and the cost of resolving
economic loss and property damage claims from individuals and businesses that either opted out of the PSC settlement and/or were excluded
from that settlement, associated claims administration costs and other items. The increase in provisions in 2016 relates primarily to the
recognition of amounts for these items, which could not be reliably estimated and provided for in 2015. After deducting amounts utilized during
the year totalling $5,540 million, comprising payments from the trust fund and qualifying settlement fund of $3,453 million and payments made
directly by BP of $2,087 million (2015 $3,279 million, comprising payments from the trust fund of $3,022 million and payments made directly by
BP of $257 million), and after adjustments for discounting, the remaining provision as at 31 December 2016 was $2,442 million (2015 $16,507
million).

Contingent liabilities
For information on Legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings on pages 261-264.

Any further outstanding Deepwater Horizon related claims are not expected to have a material impact on the group’s financial performance.

Impact upon the group income statement
The group income statement for 2016 includes a pre-tax charge of $7,134 million (2015 pre-tax charge of $11,956 million) in relation to the Gulf
of Mexico oil spill. The costs charged within production and manufacturing expenses in 2016 include the amounts charged for provisions for
business economic loss claims and economic loss and property damage claims from individuals and businesses that either opted out of the PSC
settlement and/or were excluded from that settlement, the cost of the securities claims settlement with the certified class of post-explosion
ADS purchasers which was agreed in June 2016, as well as operating and other costs. Finance costs of $494 million (2015 $247 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, amounts charged for the agreements with the United States and five Gulf coast states
that were approved by the federal district court in 2016, including amounts payable for natural resource damages, state claims and Clean Water
Act penalties, operating costs, amounts charged upon initial recognition of the trust obligation, other litigation, claims, environmental and legal
costs and estimated obligations for future costs, net of settlements agreed with the co-owners of the Macondo well and other third parties.

The total amount recognized in the income statement is analysed in the table below.

Trust fund liability – discounted
Change in discounting relating to trust fund liability
Recognition of reimbursement asset
Other

Total (credit) charge relating to the trust fund

Environmental costs
Spill response costs
Litigation and claims costs
Clean Water Act penalties
Other costs
Settlements credited to the income statement

(Profit) loss before interest and taxation
Finance costs

(Profit) loss before taxation

3. Non-current assets held for sale

2016

2015

–
–
–
–

–

–
–
6,596
–
44
–

6,640
494

7,134

–
–
–
–

–

5,303
–
5,758
551
97
–

11,709
247

11,956

$ million

Cumulative since
the incident

19,580
283
(20,000)
8

(129)

8,526
14,304
39,134
4,061
1,398
(5,681)

61,613
972

62,585

2014

–
–
(662)
–

(662)

192
–
1,137
–
114
–

781
38

819

There were no non-current assets or associated liabilities classified as held for sale as at 31 December 2016.

The assets and associated liabilities classified as held for sale at 31 December 2015 related to the dissolution of the group’s German refining
joint operation with Rosneft, which was completed on 31 December 2016.

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4. 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
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

Impairment and losses on sale of businesses and fixed assets

Disposals
Disposal proceeds and principal gains and losses on disposals by segment are described below.

Proceeds from disposals of fixed assets
Proceeds from disposals of businesses, net of cash disposed

By business
Upstream
Downstream
Other businesses and corporate

2016

2015

557
561
14

1,132

324
316
26

666

2016

2015

$ million

2014

405
474
16

895

$ million

2014

345
401
3
749

6,737
1,264
317
8,318

(102)
–
(102)

124
98
41
263

2,484
265
155
2,904

(1,080)
(178)
(1,258)

1,909

8,965

2015

1,066
1,726
2,792

769
1,747
276
2,792

$ million

2014

1,820
1,671
3,491

2,533
864
94
3,491

169
89
3
261

1,022
84
11
1,117

(3,025)
(17)
(3,042)

(1,664)

2016

1,372
1,259
2,631

839
1,646
146
2,631

At 31 December 2016, deferred consideration relating to disposals amounted to $255 million receivable within one year (2015 $41 million and
2014 $1,137 million) and $271 million receivable after one year (2015 $385 million and 2014 $333 million). In addition, contingent consideration
receivable relating to disposals amounted to $131 million at 31 December 2016 (2015 $292 million and 2014 $454 million), see Note 29 for
further information.

Upstream
In 2016, gains principally resulted from the contribution of BP’s Norwegian upstream business into Aker BP ASA and from the sale of certain
properties in the UK. Losses principally arose from the disposal of certain exploration licences in Australia and contract losses following asset
disposals in the US.

In 2015, gains principally resulted from the sale of our interests in the Central Area Transmission System in the North Sea, and from adjustments
to prior year disposals in Canada.

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.

Downstream
In 2016, gains principally resulted from the disposal of certain US and non-US midstream assets in our fuels business and the dissolution of our
German refining joint operation with Rosneft.

In 2015, gains principally resulted from the disposal of our investment in the UTA European fuel cards business and our Australian bitumen
business.

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.

Summarized financial information relating to the sale of businesses is shown in the table below. The principal transactions categorized as
business disposals in 2016 were the contribution of BP’s Norwegian upstream business into Aker BP ASA and the dissolution of the group’s
German refining joint operation with Rosneft. The principal transactions categorized as business disposals in 2015 were the sales of our

140

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4. Disposals and impairment – continued

interests in the Central Area Transmission System in the North Sea and in the UTA European fuel cards business. 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.

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 businessesb

Total consideration
Non-cash considerationc
Consideration received (receivable)d

Proceeds from the sale of businesses related to completed transactions
Depositse

Proceeds from the sale of businesses, net of cash disposedf

2016

4,794
1,202
(2,558)
(532)

2,906
25
229

3,160
593

3,753
(2,698)
223

1,278
(19)

1,259

2015

154
80
(70)
(50)

114
16
8

138
446

584
–
1,116

1,700
26

1,726

$ million

2014

1,452
182
(395)
(65)

1,174
(7)
128

1,295
280

1,575
–
96

1,671
–

1,671

a Includes amounts relating to the remeasurement to fair value of certain assets as a result of the dissolution of our German refining joint operation with Rosneft.
b 2016 gains on sale of businesses include deferred amounts not recognized in the income statement.
c Non-cash consideration principally relates to the contribution of BP’s Norwegian upstream business into Aker BP ASA in exchange for 30% interest in Aker BP ASA and the dissolution of the

group’s German refining joint operation with Rosneft.

d Consideration received from prior year business disposals or to be received from current year disposals. 2015 included $1,079 million of proceeds from our Toledo refinery partner, Husky

Energy, in place of capital commitments relating to the original divestment transaction that have not been subsequently sanctioned.

e Proceeds received in the current year in advance of business disposals, less deposits received in prior years in relation to business disposals completed in the current year.
f Proceeds are stated net of cash and cash equivalents disposed of $676 million (2015 $9 million and 2014 $32 million).

Impairments
Impairment losses and impairment reversals 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
Impairment losses and reversals related primarily to producing and midstream assets.

The 2016 impairment losses of $1,022 million related to a number of different assets, with the most significant charges arising in the North Sea.
Impairment losses within Upstream arose primarily as a result of revised cost estimates and decisions to dispose of certain assets. On 3 April
2017, BP announced that it has agreed to sell its Forties Pipeline System business to INEOS for a consideration of up to $250 million. The
transaction will lead to an impairment charge of approximately $0.4 billion, which will be included in the group income statement for 2017.

The 2016 impairment reversals of $3,025 million primarily related to the North Sea and Angola. The largest impairment reversals related to the
Andrew area cash-generating unit (CGU) in the North Sea and the PSVM and Greater Plutonio CGUs in Angola but none of these were
individually significant. In addition an impairment reversal was recorded in relation to the Block KG D6 CGU in India; and exploration costs were
also written back during the period (see Note 7). The impairment reversals arose following a reduction in the discount rate applied, changes to
future price assumptions, and also increased confidence in the progress of the KG D6 projects in India.

See Impairment of property, plant and equipment, intangible assets and goodwill within Note 1 for information on assumptions used for
impairment testing.

The 2015 impairment losses of $2,484 million included $761 million in Angola, of which $371 million related to the Greater Plutonio CGU.
Impairment losses also included $830 million in relation to CGUs in the North Sea, of which $328 million related to the Andrew area CGU. The
impairment losses primarily arose as a result of a lower price environment in the near term, and were also affected to a lesser extent by certain
technical reserves revisions and increases in decommissioning cost estimates. The 2015 impairment reversals of $1,080 million included $945
million in the North Sea business, of which $473 million related to the Eastern Trough Area Project (ETAP) CGU. The impairment reversals
mainly arose as a result of decreases in cost estimates and a reduction in the discount rate applied, offsetting the impact of lower prices in the
near term. Impairment losses and reversals related to producing assets. The discount rate used to determine the recoverable amount of the
Greater Plutonio CGU included the 2% premium for higher-risk countries. A premium was not applied in determining the recoverable amount of
the other CGUs.

The 2014 impairment losses of $6,737 million included $4,876 million in relation to CGUs in the North Sea, of which $1,964 million related to the
Valhall CGU, $660 million related to the Andrew area CGU, and $515 million related to the ETAP CGU. Impairment losses also included an $859-
million impairment of our PSVM CGU in Angola, and a $415-million impairment of the Block KG D6 CGU in India. All of the impairments related
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 discount rate used to determine the value in use of the PSVM CGU included the 2% premium for
higher-risk countries. A premium was not applied in determining the recoverable amount of the other CGUs.

Downstream
The 2016 impairment losses of $84 million principally related to certain office buildings which are expected to be vacated.

The 2015 impairment losses of $265 million arose principally in relation to certain manufacturing assets in our petrochemicals business and
certain US midstream assets, where the expected disposal proceeds were lower than the book values.

The 2014 impairment losses of $1,264 million principally related to our Bulwer Island refinery and certain midstream assets in our fuels business,
and certain manufacturing assets in our petrochemicals business.

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4. Disposals and impairment – continued

Other businesses and corporate
Impairment losses totalling $11 million, $155 million, and $317 million were recognized in 2016, 2015 and 2014 respectively. The amount for
2015 was principally in respect of our US wind business. The amount for 2014 was principally in respect of our biofuels businesses in the UK
and US.

5. Segmental analysis

The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2016, 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.

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 costs relating to the Gulf of Mexico oil spill were previously presented as a reconciling item between the sum of the results of the
reportable segments and the group results. From 2016, we have reported these costs as part of Other businesses and corporate. Prior period
comparatives have been amended to reflect this new presentation.

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.

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.

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5. Segmental analysis – continued

By business

Segment revenues

Upstream

Downstream

Rosneft

Other
businesses
and
corporate

Consolidation
adjustment
and
eliminations

Sales and other operating revenues
Less: sales and other operating revenues between segments

Third party sales and other operating revenues
Earnings from joint ventures and associates – after interest

33,188
(17,581)

15,607

167,683
(1,291)

166,392

–
–

–

1,667
(658)

1,009

723

574
60

634

608

647

(18)

5,162
1,484

6,646

590
53

643

(8,157)
–

(8,157)

(19,530)
19,530

–

(196)
–

(196)

and tax

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 (loss) before taxation

Other income statement items

Depreciation, depletion and amortization

US
Non-US

Charges for provisions, net of write-back of unused

provisions, including change in discount rate

Segment assets

Investments in joint ventures and associates

Additions to non-current assetsb

4,396
7,835

352

10,968

17,879

856
1,094

758

3,035

3,109

–
–

–

8,243

–

71
253

6,719

455

216

–
–

–

a See explanation of inventory holding gains and losses on page 142.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.

By business

Segment revenues

Sales and other operating revenues
Less: sales and other operating revenues between segments

Third party sales and other operating revenues
Earnings from joint ventures and associates – after interest and

tax

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 (loss) before taxation

Other income statement items

Depreciation, depletion and amortization

US
Non-US

Charges for provisions, net of write-back of unused provisions,

including change in discount rate

Segment assets
Investments in joint ventures and associates

Additions to non-current assetsb

Upstream

Downstream

Rosneft

Other
businesses
and
corporate

Consolidation
adjustment
and
eliminations

43,235
(21,949)

21,286

200,569
(68)

200,501

–
–

–

2,048
(941)

1,107

192

491

1,330

(202)

(937)
(30)

(967)

7,111
(1,863)

5,248

1,310
4

1,314

(13,477)
–

(13,477)

(22,958)
22,958

–

(36)
–

(36)

4,007
8,866

906
1,162

824

611

–
–

–

8,304

17,635

3,214

2,130

5,797

–

77
201

11,781

519

315

–
–

–

$ million

2016

Total
group

183,008
–

183,008

1,960

(2,027)
1,597

(430)

(1,675)

(190)

(2,295)

5,323
9,182

7,829

22,701

21,204

$ million

2015

Total
group

222,894
–

222,894

1,811

(6,029)
(1,889)

(7,918)

(1,347)

(306)

(9,571)

4,990
10,229

13,216

17,834

20,080

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143

5. 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
Earnings from joint ventures and associates – after interest and

tax

Segment results

Replacement cost profit (loss) before interest and taxation
Inventory holding gains (losses)a

Profit (loss) before interest and taxation

Finance costs
Net finance expense relating to pensions and other post-

retirement benefits

Profit before taxation

Other income statement items

Depreciation, depletion and amortization

US
Non-US

Charges for provisions, net of write-back of unused provisions,

including change in discount rate

Segment assets

Investments in joint ventures and associates

Additions to non-current assetsb

Upstream

Downstream

Rosneft

Other
businesses
and
corporate

Consolidation
adjustment
and
eliminations

65,424
(36,643)

28,781

323,486
173

323,659

–
–

–

1,989
(861)

1,128

1,089

265

2,101

(83)

8,934
(86)

8,848

3,738
(6,100)

(2,362)

2,100
(24)

2,076

(2,791)
–

(2,791)

(37,331)
37,331

–

641
–

641

4,129
8,404

984
1,336

260

713

–
–

–

7,877

22,587

3,244

3,121

7,312

–

97
213

1,652

723

784

–
–

–

$ million

2014

Total
group

353,568
–

353,568

3,372

12,622
(6,210)

6,412

(1,148)

(314)

4,950

5,210
9,953

2,625

19,156

26,492

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5. Segmental analysis – continued

By geographical area

Revenues

Third party sales and other operating revenuesa

Other income statement items

Production and similar taxes

Results

Non-US

$ million

2016

Total

65,132

117,876

183,008

155

528

683

Replacement cost profit (loss) before interest and taxation

(8,311)

6,284

(2,027)

Non-current assets

Non-current assetsb c

64,628

118,152

182,780

a Non-US region includes UK $37,119 million.
b Non-US region includes UK $18,615 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

Third party sales and other operating revenuesa

Other income statement items

Production and similar taxes

Results

Non-US

$ million

2015

Total

74,162

148,732

222,894

215

821

1,036

Replacement cost profit (loss) before interest and taxation

(12,243)

6,214

(6,029)

Non-current assets

Non-current assetsb c

67,776

111,106

178,882

a Non-US region includes UK $51,550 million.
b Non-US region includes UK $19,152 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

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

690

2,268

2,958

5,251

7,371

12,622

69,125

114,462

183,587

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.

6. Income statement analysis

Interest and other income

Interest income
Other income

Currency exchange losses charged to the income statementa

Expenditure on research and development

Finance costs

Interest payable
Capitalized at 1.81% (2015 1.75% and 2014 1.94%)b
Unwinding of discount on provisions and other payables

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 $56 million (2015 $42 million and 2014 $43 million).

2016

2015

183
323

506

698

400

226
385

611

418

$ million

2014

258
585

843

663

1,221
(244)
698
1,675

1,065
(179)
461
1,347

1,025
(185)
308
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7. 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 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

Intangible assets – exploration and appraisal expenditure

Liabilities

Net assets

Cash used in operating activities
Cash used in investing activities

2016

2015

1,274
447

1,721

1,829
524

2,353

–

$ million

2014

3,029
603

3,632

–

16,960

17,286

19,344

102

145

227

16,858

17,141

19,117

447
2,920

524
1,216

603
2,786

a 2016 included a $601-million write-off in Brazil relating to the BM-C-34 licence and various write-offs in the Gulf of Mexico totalling $611 million and India totalling $216 million, partially offset
by a write-back of $319 million in India relating to block KG D6 as a result of increased confidence in the progress of the projects. An impairment reversal of $234 million was also recorded in
2016 in relation to KG D6 in India. 2015 included a $432-million write-off in Libya as there was significant uncertainty about the timing of future drilling operations. It also included a $345-million
write-off relating to the Gila discovery in the deepwater Gulf of Mexico and a $336-million write-off relating to the Pandora discovery in Angola as development of these prospects was
considered challenging. 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. For further information see Upstream – Exploration on page 26.

During February 2017, following completion of drilling of certain exploration wells in Egypt, BP determined that no commercial hydrocarbons had
been found. The costs incurred, totalling $269 million, will be included in the group income statement for 2017.

The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2016 is shown in the
table below.

Carrying amount

$1 - 2 billion
$2 - 3 billion
$3 - 4 billion

8. Taxation

Tax on profit

Current tax

Charge for the year
Adjustment in respect of prior yearsa

Deferred tax

Origination and reversal of temporary differences in the current year
Adjustment in respect of prior yearsa b

Tax charge (credit) on profit or loss

Location

Angola; India; Egypt; Middle East
Canada; Brazil
US – Gulf of Mexico

2016

2015

1,762
(123)

1,639

(3,709)
(397)

(4,106)

(2,467)

1,910
(329)

1,581

(5,090)
338

(4,752)

(3,171)

$ million

2014

4,444
48

4,492

(3,194)
(351)

(3,545)

947

a The adjustments in respect of prior years reflect the reassessment of the current tax and deferred tax balances for prior years in light of changes in facts and circumstances during the year.
b 2016 includes the reassessment of the recognition of deferred tax assets in relation to foreign tax credits in the US.

In 2016, the total tax credit recognized within other comprehensive income was $752 million (2015 $1,140 million charge and 2014 $1,481
million credit). See Note 31 for further information. The total tax credit recognized directly in equity was $5 million (2015 $9 million charge and
2014 $36 million charge).

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 group weighted average statutory corporate income tax rate to the effective tax rate of the
group on profit or loss before taxation.

For 2016 and 2015 the items presented in the reconciliation are affected as a result of the overall tax credit for the year and the loss before
taxation. In order to provide a more meaningful analysis of the effective tax rate, the table also presents separate reconciliations for the group
excluding the impacts of the Gulf of Mexico oil spill and impairment losses and reversals, and for the impacts of the Gulf of Mexico oil spill and
impairment losses and reversals in isolation.

For 2014, the items presented in the reconciliation are affected 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

146

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8. Taxation – continued

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.

2016
excluding
impacts of
Gulf of
Mexico oil
spill and
impairments
2,914
(117)
(4)%

2016
impacts of
Gulf of
Mexico oil
spill and
impairments
(5,209)
(2,350)
45%

2015
excluding
impacts of
Gulf of
Mexico oil
spill and
impairments
4,031
945
23%

2015
impacts of
Gulf of
Mexico oil
spill and
impairments
(13,602)
(4,116)
30%

2016
(2,295)
(2,467)
107%

2014
excluding
impairments
13,166
5,036
38%

2014
impacts of
impairments
(8,216)
(4,089)
50%

2015
(9,571)
(3,171)
33%

$ million

2014
4,950
947
19%

(15)

26
(9)

–
(24)
1

(15)
1
(4)

–

3
–

(2)
–
–

–

–
(2)
45

(27)
11

(4)
30
(2)

(11)

19
(3)
107

(7)

17
(8)

–
(3)
18

(23)
1
23

% of profit or loss before taxation

–

(5)
–

(2)
–
–

–

–
(1)
30

–

(14)
3

(3)
1
(8)

(4)

10
(1)
33

(5)

(2)

4
(4)

–
(1)
4

–
–
38

–

(3)
–

–
–
–

(2)

–
–
50

(14)

(6)

17
(10)

1
(1)
10

–
–
19

Profit (loss) before taxation
Tax charge (credit) on profit or loss
Effective tax rate

Tax rate computed at the weighted

average statutory ratea

Increase (decrease) resulting from
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
Disposal impactsb
Foreign exchange
Items not deductible for tax

purposes

Decrease in rate of UK

supplementary chargec

Other

Effective tax rate

a Calculated based on the statutory corporate income tax rate applicable in the countries in which the group operates, weighted by the profits and losses before tax in the respective countries. It

reflects the mix of profits and losses arising in higher tax rate jurisdictions (primarily the Upstream segment) and lower tax rate jurisdictions (primarily the Downstream segment).

b In 2016 this relates primarily to the tax impact on the contribution of BP’s Norwegian upstream business into Aker BP ASA.
c This relates to the deferred tax impact of the reductions in the UK supplementary charge tax rate applicable to profits arising in the North Sea from 20% to 10% in 2016 and from 32% to 20%

in 2015.

Deferred tax

Analysis of movements during the year in the net deferred tax liability
At 1 January
Exchange adjustments
Charge (credit) for the year in the income statement
Charge (credit) for the year in other comprehensive income
Charge (credit) for the year in equity
Acquisitions and disposals
At 31 December

2016
8,054
(71)
(4,106)
(714)
(5)
(661)
2,497

$ million

2015
11,584
86
(4,752)
1,140
9
(13)
8,054

The following table provides an analysis of deferred tax in the income statement and the balance sheet by category of temporary difference:

Deferred tax liability

Depreciation
Pension plan surpluses
Derivative financial instruments
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 creditsa
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

2016

2015

2014

2016

2015

81
(12)
(230)
(122)
(283)

98
591
(6)
(5,177)
249
422
(3,823)

(4,106)

(102)
84
(326)
59
(285)

12
(2,513)
62
256
(2,239)
(45)
(4,467)

(4,752)

(2,178)
(272)
527
(1,805)
(3,728)

492
52
166
589
(1,397)
281
183

(3,545)

26,864
171
761
1,254
29,050

(1,889)
(12,108)
(734)
(5,225)
(5,458)
(1,139)
(26,553)

2,497

7,238
4,741

28,712
878
961
1,266
31,817

(1,972)
(13,737)
(710)
(43)
(5,985)
(1,316)
(23,763)

8,054

9,599
1,545

a The increase in tax credits in 2016 reflects the impact of a loss carry-back claim in the US, displacing foreign tax credits utilized in prior periods which are now carried forward.

BP Annual Report and Form 20-F 2016

147

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8. Taxation – continued

The recognition of deferred tax assets of $3,839 million (2015 $1,067 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. Of this
amount, $2,974 million relates to the US (2015 $nil).

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 US state tax lossesa
Unused tax losses – other jurisdictionsb
Unused tax credits

of which – arising in the UKc
– arising in the USd

Deductible temporary differencese
Taxable temporary differences associated with investments in subsidiaries and equity-accounted entities

2016
9.6
5.2
19.2
17.1
2.0
26.7
3.1

$ billion

2015
9.6
2.1
20.4
17.5
2.8
23.2
3.9

a These losses expire in the period 2017–2036 with applicable tax rates ranging from 4% to 12%.
b The majority of the unused tax losses have no fixed expiry date.
c The UK unused tax credits arise predominantly in overseas branches of UK entities based in jurisdictions with higher statutory corporate income tax rates than the UK. 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 in respect of overseas
tax. These tax credits have no fixed expiry date.

d The US unused tax credits expire in the period 2017-2026.
e The majority comprises fixed asset temporary differences in the UK. Substantially all of the temporary differences have no expiry date.

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 and losses
Deferred tax benefit arising from the reversal of a previous write-down of deferred tax assets
Deferred tax benefit relating to the recognition of previously unrecognized tax credits and losses
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset

2016
40
269
394
55

2015
123
–
–
768

$ million

2014
171
–
–
153

9. Dividends

The quarterly dividend paid on 31 March 2017 in respect of the fourth quarter 2016 was 10 cents per ordinary share ($0.60 per American
Depositary Share (ADS)). The corresponding amount in sterling was announced on 20 March 2017. 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.

Pence per share

Cents per share

2016

2015

2014

2016

2015

2014

2016

2015

$ million

2014

Dividends announced and paid

in cash
Preference shares
Ordinary shares

March
June
September
December

Dividend announced, paid in

March 2017

7.0125
6.9167
7.5578
7.9313
29.4183

6.6699
6.5295
6.5488
6.6342
26.3824

5.7065
5.8071
5.9593
6.3769
23.8498

10.00
10.00
10.00
10.00
40.00

10.00

10.00
10.00
10.00
10.00
40.00

9.50
9.75
9.75
10.00
39.00

1,099
1,168
1,161
1,182
4,611

1,303

1,708
1,691
1,717
1,541
6,659

1,426
1,572
1,122
1,728
5,850

The details of the scrip dividends issued are shown in the table below.

Number of shares issued (thousand)
Value of shares issued ($ million)

2016
548,005
2,858

2015
102,810
642

2014
165,644
1,318

The financial statements for the year ended 31 December 2016 do not reflect the dividend announced on 7 February 2017 and paid in March
2017; this will be treated as an appropriation of profit in the year ended 31 December 2017.

10. Earnings per ordinary share

Per ordinary share
Basic earnings per share
Diluted earnings per share

Per ADS
Basic earnings per share
Diluted earnings per share

2016
0.61
0.60

2016
0.04
0.04

Cents per share

2015
(35.39)
(35.39)

2014
20.55
20.42

Dollars per share

2015
(2.12)
(2.12)

2014
1.23
1.23

Basic earnings per ordinary share amounts are calculated by dividing the profit (loss) 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 includes certain shares
that will be issuable in the future under employee share-based payment plans and excludes treasury shares, which includes shares held by the
Employee Share Ownership Plan trusts (ESOPs).

148

BP Annual Report and Form 20-F 2016

10. Earnings per ordinary share – continued

For the diluted earnings per share calculation, the weighted average number of shares outstanding during the year is adjusted for the average
number of shares that are potentially issuable in connection with employee share-based payment plans using the treasury stock method. If the
inclusion of potentially issuable shares would decrease loss per share, the potentially issuable shares are excluded from the weighted average
number of shares outstanding used to calculate diluted earnings per share. A dilutive effect relating to potentially issuable shares has not been
included, therefore, in the calculation of diluted earnings per share for 2015.

Profit (loss) attributable to BP shareholders
Less: dividend requirements on preference shares

Profit (loss) for the year attributable to BP ordinary shareholders

Basic weighted average number of ordinary shares
Potential dilutive effect of ordinary shares issuable under employee share-based payment

plans

Weighted average number of ordinary shares outstanding used to calculate diluted earnings

per share

Basic weighted average number of ordinary shares - ADS equivalent
Potential dilutive effect of ordinary shares (ADS equivalent) issuable under employee

share-based payment plans

Weighted average number of ordinary shares (ADS equivalent) outstanding used to calculate

2016

115
1

114

2015

(6,482)
2

(6,484)

$ million

2014

3,780
2

3,778

2016

2015

2014

18,744,800

18,323,646

18,385,458

Shares thousand

110,519

–

111,836

18,855,319

18,323,646

18,497,294

2016

2015

2014

3,124,133

3,053,941

3,064,243

Shares thousand

18,420

–

18,639

diluted earnings per share

3,142,553

3,053,941

3,082,882

The number of ordinary shares outstanding at 31 December 2016, excluding treasury shares, and including certain shares that will be issuable in
the future under employee share-based payment plans was 19,438,990,091. Between 31 December 2016 and 16 March 2017, the latest
practicable date before the completion of these financial statements, there was a net increase of 71,878,542 in the number of ordinary shares
outstanding as a result of share issues in relation to employee share-based payment plans.

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 80-110.

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 is also shown.

Share options

Outstanding
Exercisable
Dilutive effect

2016

Weighted
average
exercise
price $

3.85
4.59
n/a

Number of

optionsa b

thousand

26,284
498
3,380

2015

Weighted
average
exercise
price $

8.54
10.21
n/a

Number of

optionsa b

thousand

70,049
46,520
2,659

a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2016 the quoted market price of one BP ordinary share was £5.10 (2015 £3.54).

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 is also shown.

Share plans

Vesting

Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years

Dilutive effect

2016

2015

Number of
sharesa
thousand

92,529
94,760
102,342
680
319
290,630
113,012

78,823
76,779
89,654
41,479
695
287,430
101,984

a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).

There has been a net decrease of 28,236,653 in the number of potential ordinary shares relating to employee share-based payment plans
between 31 December 2016 and 16 March 2017.

BP Annual Report and Form 20-F 2016

149

F
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11. Property, plant and equipment

Land
and land
Improvements

Buildings

Oil and
gas
propertiesa

Plant,
machinery
and
equipment

Fixtures,
fittings and
office
equipment

Transportation

3,194
(119)
106
46
–
–
(161)

3,066

642
(9)
40
–
9
(2)
–
(96)

584

2,877
(37)
24
–
–
–
(629)

2,235

1,157
(44)
166
–
123
–
–
(340)

1,062

215,566
–
12,036
–
–
1,629
(13,667)

215,564

123,831
–
11,213
–
518
(2,923)
5
(10,216)

122,428

45,744
(342)
1,699
793
(1,505)
–
(2,664)

43,725

20,652
(264)
1,740
(1,319)
11
(12)
–
(2,122)

18,686

2,866
(127)
192
–
–
–
(261)

2,670

2,084
(96)
214
–
79
–
–
(259)

2,022

14,038
(9)
156
–
–
–
(185)

14,000

9,439
(6)
397
–
256
(101)
–
(162)

9,823

Oil depots,
storage
tanks and
service
stations

8,418
(375)
568
–
–
–
(988)

7,623

5,140
(218)
384
–
4
(4)
–
(785)

4,521

$ million

Total

292,703
(1,009)
14,781
839
(1,505)
1,629
(18,555)

288,883

162,945
(637)
14,154
(1,319)
1,000
(3,042)
5
(13,980)

159,126

2,482

1,173

93,136

25,039

648

4,177

3,102

129,757

Cost

At 1 January 2016
Exchange adjustments
Additions
Acquisitions
Remeasurementsb
Transfers
Deletions

At 31 December 2016

Depreciation

At 1 January 2016
Exchange adjustments
Charge for the year
Remeasurementsb
Impairment losses
Impairment reversals
Transfers
Deletions

At 31 December 2016

Net book amount at 31

December 2016

Cost

At 1 January 2015
Exchange adjustments
Additions
Acquisitions
Transfers
Reclassified as assets held for

sale
Deletions

3,415
(259)
96
–
–

–
(58)

3,061
(144)
122
–
–

(66)
(96)

200,514
–
14,574
–
1,039

–
(561)

48,815
(1,828)
1,114
27
–

(1,364)
(1,020)

At 31 December 2015

3,194

2,877

215,566

45,744

3,031
(89)
129
–
–

(31)
(174)

2,866

1,983
(56)
238
1
–
–

(24)
(58)

13,819
(61)
493
–
–

–
(213)

9,046
(772)
551
–
–

281,701
(3,153)
17,079
27
1,039

–
(407)

(1,461)
(2,529)

14,038

8,418

292,703

8,933
(33)
426
283
(18)
–

–
(152)

9,439

5,724
(452)
323
7
(159)
–

151,009
(1,516)
14,923
2,645
(1,258)
21

–
(303)

(1,095)
(1,784)

5,140

162,945

1,197
(51)
135
2
–
–

(33)
(93)

111,175
–
12,004
2,113
(1,079)
21

–
(403)

21,358
(914)
1,760
225
(2)
–

(1,038)
(737)

639
(10)
37
14
–
–

–
(38)

642

1,157

123,831

20,652

2,084

2,552

1,720

91,735

25,092

782

4,599

3,278

129,758

–
–

2
2

21
84

266
297

–
–

241
242

–
–

530
625

29,177
27,755

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.
b Relates to the remeasurement to fair value of previously held interests in certain assets as a result of the dissolution on 31 December 2016 of the group’s German refining joint operation with

Rosneft.

12. Capital commitments

Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at
31 December 2016 amounted to $11,207 million (2015 $10,379 million). BP’s share of capital commitments of joint ventures amounted to
$522 million (2015 $586 million).

150

BP Annual Report and Form 20-F 2016

Depreciation

At 1 January 2015
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Transfers
Reclassified as assets held for

sale
Deletions

At 31 December 2015

Net book amount at 31

December 2015

Assets held under finance leases at net book
amount included above

At 31 December 2016
At 31 December 2015

Assets under construction included above

At 31 December 2016
At 31 December 2015

13. Goodwill and impairment review of goodwill

Cost

At 1 January
Exchange adjustments
Acquisitions
Deletions

At 31 December

Impairment losses
At 1 January
Exchange adjustments
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

2016

$ million

2015

12,236
(544)
247
(134)

11,805

12,482
(237)
5
(14)

12,236

609
5
(3)

611

614
–
(5)

609

11,194

11,627

11,868

2016

7,726
3,401
67

$ million

2015

7,812
3,761
54

11,194

11,627

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

F
n
a
n
c
a

2016

7,726
26,035

$ million

2015

7,812
12,894

s
t
a
t
e
m
e
n
t
s

The table above shows the carrying amount of goodwill for the segment at year-end and the excess of the recoverable amount, based upon a
fair value less costs of disposal calculation, over the carrying amount (the headroom) at the date of the test.

The fair value less costs of disposal is based on the cash flows expected to be generated by the projected oil or natural gas production profiles
up to the expected dates of cessation of production of each producing field, based on current estimates of reserves and resources, appropriately
risked for the purposes of goodwill impairment testing. Midstream and supply and trading activities and equity-accounted entities are generally
not included in the impairment review of goodwill, because they are not part of the grouping of cash-generating units to which the goodwill
relates and which is used to monitor the goodwill for internal management purposes. Where such activities form part of a wider Upstream cash-
generating unit, they are reflected in the test. 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 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. 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.

The 2016 review for impairment was carried out during the third quarter following the change in price assumptions and discount rate as
disclosed in Note 1. In prior years the review was carried out during the fourth quarter. In the absence of any indicators of impairment in other
quarters, the review will be carried out in the third quarter in future years. The key assumptions used in the fair value less costs of disposal
calculation are oil and natural gas prices, production volumes and the discount rate. Price assumptions and discount rate assumptions used were
as disclosed in Note 1. The fair value less costs of disposal calculations have been prepared solely for the purposes of determining whether the
goodwill balance was impaired. Estimated future cash flows were prepared on the basis of certain assumptions prevailing at the time of the test.
The actual outcomes may differ from the assumptions made. For example, reserves and resources estimates and production forecasts are
subject to revision as further technical information becomes available and economic conditions change, and future commodity prices may differ
from the forecasts used in the calculations.

BP Annual Report and Form 20-F 2016

151

13. Goodwill and impairment review of goodwill – continued

The sensitivities to different variables have been estimated using certain simplifying assumptions. For example, lower oil and gas price
sensitivities do not reflect the specific impacts for each contractual arrangement and will not capture fully any favourable impacts that may arise
from cost deflation. Therefore a detailed calculation at any given price or production profile may produce a different result.

It is estimated that if the oil price assumption for all future years (the first five years, and the long-term assumption from 2022 onwards) was
approximately $13 per barrel lower in each year, this would cause the recoverable amount to be equal to the carrying amount of goodwill and
related net non-current assets of the segment. It is estimated that if the gas price assumption for all future years was approximately $2 per
mmBtu lower in each year, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net 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
889mmboe per year (2015 911mmboe per year). It is estimated that if production volume were to be reduced by approximately 4% for this
period, this would cause the recoverable amount to be equal to the carrying amount of goodwill and related net non-current assets of the
segment.

It is estimated that if the post-tax discount rate was approximately 9% for the entire portfolio, an increase of 3% for all countries not considered
‘higher risk’ and 1% for countries considered ‘higher risk’, this would cause the recoverable amount to be equal to the carrying amount of
goodwill and related net non-current assets of the segment.

Downstream

Goodwill

Lubricants

2,571

Other

830

2016

Total

Lubricants

3,401

3,109

Other

652

$ million

2015

Total

3,761

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 Lubricants’ recoverable amount performed in the most recent detailed calculation in 2013
were used for the 2016 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 BP’s 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.

14. Intangible assets

Cost

At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers
Reclassified as assets held for sale
Deletions

At 31 December

Amortization

At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Transfers
Reclassified as assets held for sale
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 7.

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Exploration
and appraisal
expenditurea

Other
intangibles

19,856
–
–
2,896
(1,629)
–
(2,599)

18,524

2,570
–
1,274
62
(5)
–
(2,337)

1,564

16,960

17,286

4,055
(149)
15
251
–
–
(137)

4,035

2,681
(96)
351
–
–
–
(124)

2,812

1,223

1,374

2016

Total

23,911
(149)
15
3,147
(1,629)
–
(2,736)

22,559

5,251
(96)
1,625
62
(5)
–
(2,461)

4,376

18,183

18,660

Exploration
and appraisal
expenditurea

Other
intangibles

21,723
–
–
1,197
(1,039)
–
(2,025)

19,856

2,379
–
1,829
–
(21)
–
(1,617)

2,570

17,286

19,344

4,268
(187)
–
234
–
(18)
(242)

4,055

2,705
(75)
296
–
–
(15)
(230)

2,681

1,374

1,563

$ million

2015

Total

25,991
(187)
–
1,431
(1,039)
(18)
(2,267)

23,911

5,084
(75)
2,125
–
(21)
(15)
(1,847)

5,251

18,660

20,907

15. 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 (loss) 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

$ million

2014
12,208
1,210
125
1,085
515
570

(15)
555

2016
10,081
1,612
156
1,456
490
966

5
971

10,874
3,257
14,131

2,087
3,520
5,607

8,524

8,524
85
8,609

2015a
9,588
785
188
597
625
(28)

(1)
(29)

11,163
2,515
13,678

1,855
3,500
5,355

8,323

8,323
89
8,412

a The loss for 2015 shown in the table above included $711 million relating to BP`s share of impairment losses recognized by joint ventures, a significant element of which related to the Angola

LNG plant.

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

Product
LNG, crude oil and oil products, natural gas, refinery

operating costs, plant processing fees

2016

Amount
receivable at
31 December
291

2016

Amount
payable at
31 December

2015

Amount
receivable at
31 December
245

2015

Amount
payable at
31 December

Sales
2,841

Purchases

Sales
2,760

Purchases

Sales
3,148

Purchases

$ million

2014

Amount
receivable at
31 December
300

$ million

2014

Amount
payable at
31 December

943

120

861

104

907

129

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.

16. 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
Other associates

Income statement

Earnings from associates –
after interest and tax

2016
647
347
994

2015
1,330
509
1,839

2014
2,101
701
2,802

2016
8,243
5,849
14,092

$ million

Balance sheet

Investments
in associates

2015
5,797
3,625
9,422

The associate that is material to the group at both 31 December 2016 and 2015 is Rosneft.

BP owns 19.75% of the voting shares of Rosneft which are listed on the MICEX stock exchange in Moscow and its global depository receipts
are listed on the London Stock Exchange. The Russian federal government, through its investment company JSC Rosneftegaz, owned 50.0%
plus one share of the voting shares of Rosneft at 31 December 2016.

BP classifies its investment in Rosneft as an associate because, in management’s judgement, BP has significant influence over Rosneft; see
Interests in other entities within Note 1 for further information. The group’s investment in Rosneft is a foreign operation whose functional

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16. Investments in associates – continued

currency is the Russian rouble. The increase in the group`s equity-accounted investment balance for Rosneft at 31 December 2016 compared
with 31 December 2015 principally relates to foreign exchange effects which have been recognized in other comprehensive income.

The value of BP’s 19.75% shareholding in Rosneft based on the quoted market share price of $6.50 per share (2015 $3.48 per share) was
$13,604 million at 31 December 2016 (2015 $7,283 million).

The following table provides summarized financial information relating to Rosneft. This information is presented on a 100% basis and reflects
adjustments made by BP to Rosneft’s 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. These adjustments have increased the reported profit for 2016, 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.

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
142,856
19,367
5,230
14,137
3,428
71
10,638
(13,038)
(2,400)

2016
74,380
7,094
1,747
5,347
1,797
273
3,277
4,203
7,480

129,403
37,914
167,317

46,284
71,980
118,264

49,053
7,316
41,737

2015
84,071
12,253
3,696
8,557
1,792
30
6,735
(4,111)
2,624

84,689
34,891
119,580

25,691
63,554
89,245

30,335
982
29,353

The group received dividends, net of withholding tax, of $332 million from Rosneft in 2016 (2015 $271 million and 2014 $693 million).

Summarized financial information for the group’s share of associates is shown below.

$ million

BP share

2014

Total

37,938
4,763
1,040
3,723
907
14
2,802

(2,565)
237

Rosneft

Other

28,214
3,825
1,033
2,792
677
14
2,101

(2,575)
(474)

9,724
938
7
931
230
–
701

10
711

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

Group investment in associates
Group share of net assets

(as above)

Loans made by group

companies to associates

Rosnefta

Other

14,690
1,401
345
1,056
355
54
647

830
1,477

25,557
7,488
33,045
9,141
14,216
23,357
9,688
1,445
8,243

5,377
525
22
503
156
–
347

(2)
345

7,848
2,002
9,850
1,827
2,934
4,761
5,089
–
5,089

2016

Total

20,067
1,926
367
1,559
511
54
994

828
1,822

33,405
9,490
42,895
10,968
17,150
28,118
14,777
1,445
13,332

Rosnefta

Other

16,604
2,420
730
1,690
354
6
1,330

(812)
518

16,726
6,891
23,617
5,074
12,552
17,626
5,991
194
5,797

6,000
661
6
655
146
–
509

(2)
507

3,914
1,621
5,535
1,134
1,311
2,445
3,090
–
3,090

2015

Total

22,604
3,081
736
2,345
500
6
1,839

(814)
1,025

20,640
8,512
29,152
6,208
13,863
20,071
9,081
194
8,887

8,243

5,089

13,332

5,797

3,090

8,887

–
8,243

760
5,849

760
14,092

–
5,797

535
3,625

535
9,422

a From 1 October 2014, Rosneft adopted hedge accounting in relation to a portion of highly probable future export revenue denominated in US dollars over a five-year period. Foreign exchange
gains and losses arising on the retranslation of borrowings denominated in currencies other than the Russian rouble and designated as hedging instruments are recognized initially in other
comprehensive income, and are reclassified to the income statement as the hedged revenue is recognized.

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16. Investments in associates – continued

Transactions between the group and its associates are summarized below.

Sales to associates

Product

LNG, crude oil and oil products, natural gas

Purchases from associates

Product

Crude oil and oil products, natural gas, transportation tariff

2016

Amount
receivable at
31 December

765

2016

Amount
payable at
31 December

2015

Amount
receivable at
31 December

1,058

2015

Amount
payable at
31 December

Sales

5,302

Purchases

Sales

9,589

Purchases

$ million

2014

Amount
receivable at
31 December

1,258

$ million

2014

Amount
payable at
31 December

2,000

11,619

2,026

22,703

2,307

Sales

4,210

Purchases

8,873

In addition to the transactions shown in the table above, in 2016 the group completed the dissolution of its German refining joint operation with
Rosneft. In 2015, the group acquired a 20% participatory interest in Taas-Yuryakh Neftegazodobycha, a Rosneft subsidiary.

The terms of the outstanding balances receivable from associates are typically 30 to 45 days. The balances are unsecured and will be settled in
cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the income
statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.

The majority of the sales to and purchases from associates relate to crude oil and oil products transactions with Rosneft.

BP has commitments amounting to $12,768 million (2015 $11,446 million), primarily in relation to contracts with its associates for the purchase
of transportation capacity.

17. Other investments

Equity investmentsa
Other

a The majority of equity investments are unlisted.

2016

$ million

2015

Current Non-current

Current

Non-current

2
42

405
628

1,033

–
219

219

397
605

1,002

Other non-current investments includes $628 million relating to life insurance policies (2015 $605 million) which have been designated as
financial assets at fair value through profit and loss. Their valuation methodology is in level 3 of the fair value hierarchy.

18. Inventories

Crude oil
Natural gas
Refined petroleum and petrochemical products

Supplies

Trading inventories

2016

5,531
155
9,198

14,884
2,388

17,272
383

17,655

$ million

2015

3,467
251
7,470

11,188
2,626

13,814
328

14,142

Cost of inventories expensed in the income statement

132,219

164,790

The inventory valuation at 31 December 2016 is stated net of a provision of $501 million (2015 $1,295 million) to write inventories down to their
net realizable value. The net credit to the income statement in the year in respect of inventory net realizable value provisions was $769 million
(2015 $1,507 million credit).

Trading inventories are valued using quoted benchmark bid prices adjusted as appropriate for location and quality differentials. They are
predominantly categorized within level 2 of the fair value hierarchy.

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19. 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

2016

$ million

2015

Current Non-current

Current

Non-current

13,393
1,056
5,352

19,801

194
680

874

–
–
815

815

–
659

659

13,682
1,303
5,908

20,893

686
744

1,430

72
–
1,249

1,321

–
895

895

20,675

1,474

22,323

2,216

a See Note 2 for further information.

Trade and other receivables are predominantly non-interest bearing. See Note 28 for further information.

20. Valuation and qualifying accounts

At 1 January
Charged to costs and expenses
Charged to other accountsa
Deductions

At 31 December

a Principally exchange adjustments.

2016

2015

$ million

2014

Accounts
receivable

Fixed asset
investments

Accounts
receivable

Fixed asset
investments

Accounts
receivable

Fixed asset
investments

447
120
(7)
(168)

392

435
55
(2)
(153)

335

331
243
(23)
(104)

447

517
195
(4)
(273)

435

343
127
(24)
(115)

331

168
438
(2)
(87)

517

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 judgements made in relation to the recoverability of trade receivables see Impairment of loans and receivables
within Note 1.

21. Trade and other payables

Financial liabilities
Trade payables
Amounts payable to joint ventures and associates
Other payablesa

Non-financial liabilities

Other payables

2016

$ million

2015

Current Non-current

Current

Non-current

21,575
2,120
12,079

35,774

–
–
13,760

13,760

16,838
2,130
10,775

29,743

2,141
37,915

186
13,946

2,206
31,949

–
–
2,351

2,351

559
2,910

a The majority of non-current other payables relate to the Gulf of Mexico oil spill. See Note 2 for further information.

Trade and other payables, other than those relating to the Gulf of Mexico oil spill, are predominantly interest free. See Note 28 for further
information.

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22. Provisions

At 1 January 2016
Exchange adjustments
Acquisitions
Increase (decrease) in existing provisions
Write-back of unused provisions
Unwinding of discount
Change in discount rate
Utilization
Reclassified to other payables
Deletions

At 31 December 2016

Of which – current

– non-current

Of which – Gulf of Mexico oil spilla

Decommissioning

Environmental

Litigation and
claims

Clean Water
Act penalties

18,946
(607)
–
(804)
–
162
738
(17)
(624)
(1,352)

16,442

244
16,198

–

7,557
(3)
6
262
(96)
62
18
(239)
(5,970)
(13)

1,584

315
1,269

–

7,134
–
4
6,650
(36)
36
20
(5,625)
(5,012)
(9)

3,162

2,460
702

2,442

4,129
–
–
–
–
38
–
–
(4,167)
–

–

–
–

–

$ million

Total

41,114
(693)
42
7,386
(431)
310
808
(6,764)
(15,962)
(1,386)

24,424

4,012
20,412

2,442

Other

3,348
(83)
32
1,278
(299)
12
32
(883)
(189)
(12)

3,236

993
2,243

–

a 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 2016 are provisions for deferred employee compensation of $422 million (2015 $484 million).

For information on significant estimates and judgements made in relation to provisions, including those for the Gulf of Mexico oil spill, see
Provisions and contingencies within Note 1.

23. 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 an
employee’s 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.

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, 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, all employees now accrue benefits under a cash balance formula. Benefits previously accrued under final salary formulas are legally
protected. Retiring US employees typically take their pension benefit in the form of a lump sum payment upon retirement. The plan is funded
and its assets are overseen by a fiduciary Investment Committee composed of six 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 to retired employees and their dependants (and, in certain cases, life insurance coverage);
the entitlement to these benefits is usually based on the employee remaining in service until a specified 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 an employee’s pensionable salary and length of service. The returns
on the notional contributions made by both the company and employees are based on the interest rate which is set out in German tax law.
Retired German employees take their pension benefit typically in the form of an annuity. The German plans are governed by legal agreements
between BP and the works council or between BP and the trade union.

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 2016 the aggregate level of contributions was $651 million (2015 $1,066 million and 2014 $1,252 million). The aggregate level of
contributions in 2017 is expected to be approximately $1,050 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 seven years is agreed. The funding agreement can be terminated unilaterally by
either party with two years’ notice. Contractually committed funding therefore represents nine years of future contributions, which amounted to
$5,761 million at 31 December 2016, of which $2,410 million relates to past service. This amount is included in the group’s committed cash

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flows relating to pensions and other post-retirement benefit plans as set out in the table of contractual obligations on page 243. The surplus
relating to the primary UK pension plan is recognized on the balance sheet on the basis that the company is entitled to a refund of any remaining
assets once all members have left the plan.

Pension contributions in the US are determined by legislation and are supplemented by discretionary contributions. All of the contributions made
into the US pension plan in 2016 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 2016.

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 2016. The UK plans are subject to a formal actuarial valuation every three years;
valuations are required more frequently in many other countries. The most recent formal actuarial valuation of the UK pension plans was as at
31 December 2014. 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

2016

2015

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

2.7
4.6
3.0
3.0
3.2

2016

4.0
3.9
3.1

3.9
4.4
3.0
3.0
3.0

2015

3.9
3.6
3.1

UK
2014

3.6
4.5
3.0
3.0
3.0

UK
2014

4.8
4.6
3.4

2016

2015

3.9
4.2
–
–
1.8

2016

4.2
4.0
1.5

4.0
3.9
–
–
1.5

2015

3.8
3.7
1.6

US
2014

3.7
4.0
–
–
1.6

US
2014

4.6
4.3
2.1

2016

2015

1.7
3.0
1.5
0.5
1.6

2016

2.7
2.4
1.8

2.4
3.2
1.6
0.6
1.8

2015

2.3
2.0
2.0

Eurozone
2014

2.0
3.4
1.8
0.7
2.0

Eurozone
2014

3.9
3.6
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. In other countries, including the Eurozone, we use
this approach, 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. For 2016 the assumed rate of
increase for the UK plans also reflects the probability of exceeding a cap or breaching a floor for pension increases as set out in the plan rules; this
change resulted in a reduction in the pension obligation of $865 million.

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 0.8% 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 applicable 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

2016

2015

UK
2014

2016

2015

US
2014

2016

2015

Years

Eurozone
2014

Life expectancy at age 60 for a male currently

aged 60

28.0

28.5

28.3

25.7

25.6

25.0

24.9

24.7

Life expectancy at age 60 for a male currently

aged 40

30.0

31.0

30.9

27.5

27.4

27.6

27.5

27.3

Life expectancy at age 60 for a female currently

aged 60

29.5

29.4

29.3

29.2

29.1

28.9

28.8

28.7

Life expectancy at age 60 for a female currently

aged 40

31.9

31.8

31.0

30.9

31.3

31.2

31.1

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, which are expected to generate a higher level of return over the long term, with an
acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the
total portfolio, the investment portfolios are highly diversified.

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 the asset portfolio with the pension liabilities. There is a similar agreement in
place in the US. During 2016, the UK and the US plans switched 4% and nil respectively from equities to bonds.

BP’s primary plan in the UK uses a liability driven investment (LDI) approach for part of the portfolio, a form of investing designed to match the
movement in pension plan assets with the impact of interest rate changes and inflation assumption changes on the projected benefit obligation.

158

BP Annual Report and Form 20-F 2016

23. Pensions and other post-retirement benefits – continued

The current asset allocation policy for the major plans at 31 December 2016 was as follows:

Asset category

Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate

58
35
7

55
45
–

The amounts invested under the LDI programme as at 31 December 2016 were $423 million (2015 $329 million) of government-issued nominal
bonds and $9,384 million (2015 $6,421 million) of index-linked bonds. This is partly funded by short-term sale and repurchase agreements,
proceeds from which are shown separately in the table below.

In addition, the primary UK plan entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $4,450 million
(2015 $2,651 million) of the corporate bond portfolio. At 31 December 2016 the fair value liability of these swaps was $144 million (2015
$17 million fair value asset) and is included in other assets in the table below.

Some of the group’s pension plans in other countries also use derivative financial instruments as part of their asset mix to manage the level of risk.

The group’s main pension plans do not invest directly in either securities or property/real estate of the company or of any subsidiary.

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 160.

Fair value of pension plan assets

At 31 December 2016

Listed equities – developed markets
– emerging markets

Private equity
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Property
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments

At 31 December 2015

Listed equities – developed markets
– emerging markets

Private equity
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Property
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments

At 31 December 2014

Listed equities – developed markets
– emerging markets

Private equity
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Property
Cash
Other

UKa

USb

Eurozone

Other

11,494
2,549
2,754
489
9,384
4,042
1,970
547
(68)
(2,981)

30,180

13,474
2,305
2,933
393
6,425
4,357
2,453
564
110
(1,791)

31,223

16,190
2,719
2,983
642
892
4,687
2,403
1,145
112

31,773

2,283
220
1,442
1,438
–
1,732
6
105
90
–

7,316

2,329
226
1,522
1,527
–
1,717
6
116
67
–

7,510

3,026
293
1,571
1,535
–
1,726
7
134
63

8,355

436
54
1
821
4
427
45
17
74
–

363
46
–
448
–
259
28
83
83
–

1,879

1,310

423
49
1
685
5
551
48
10
102
–

371
50
4
492
–
367
58
139
50
–

1,874

1,531

415
45
2
753
9
541
51
85
72

420
47
26
604
–
340
69
191
38

1,973

1,735

$ million

Total

14,576
2,869
4,197
3,196
9,388
6,460
2,049
752
179
(2,981)

40,685

16,597
2,630
4,460
3,097
6,430
6,992
2,565
829
329
(1,791)

42,138

20,051
3,104
4,582
3,534
901
7,294
2,530
1,555
285

43,836

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.

BP Annual Report and Form 20-F 2016

159

F
n
a
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a

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t
a
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e
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t
s

23. Pensions and other post-retirement benefits – continued

Analysis of the amount charged to profit (loss) 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
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 participantsc
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Acquisitions
Disposals
Remeasurements
Benefit obligation at 31 Decembera e
Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsa f
Contributions by plan participantsc
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Disposals
Remeasurementsf
Fair value of plan assets at 31 Decemberg
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

$ million

2016

Total

790
1
8
799
264
1,063
(1,471)
1,661
190

4,813
(7,789)

446
34
(2,496)

48,346
(5,947)
799
1,661
26
(2,208)
(615)
4
(399)
7,309
48,976

42,138
(5,977)
1,471
26
651
(2,208)
(229)
4,813
40,685
(8,291)

584
(8,875)
(8,291)

310
(24)
–
286
194
480
(287)
417
130

330
(239)

9
(62)
38

10,643
–
286
417
–
(821)
(284)
–
–
292
10,533

7,510
–
287
–
10
(821)
–
330
7,316
(3,217)

–
(3,217)
(3,217)

76
7
9
92
7
99
(47)
159
112

53
(622)

12
26
(531)

6,640
(282)
92
159
2
(78)
(301)
4
–
584
6,820

1,874
(76)
47
2
57
(78)
–
53
1,879
(4,941)

22
(4,963)
(4,941)

71
1
(1)
71
33
104
(51)
80
29

8
4

(5)
15
22

2,089
23
71
80
6
(117)
(24)
–
(399)
(14)
1,715

1,531
15
51
6
45
(117)
(229)
8
1,310
(405)

32
(437)
(405)

333
17
–
350
30
380
(1,086)
1,005
(81)

4,422
(6,932)

430
55
(2,025)

28,974
(5,688)
350
1,005
18
(1,192)
(6)
–
–
6,447
29,908

31,223
(5,916)
1,086
18
539
(1,192)
–
4,422
30,180
272

530
(258)
272

519
(247)
272

(36)
(3,181)
(3,217)

(316)
(4,625)
(4,941)

(83)
(322)
(405)

84
(8,375)
(8,291)

(29,661)
(247)
(29,908)

(7,352)
(3,181)
(10,533)

(2,195)
(4,625)
(6,820)

(1,393)
(322)
(1,715)

(40,601)
(8,375)
(48,976)

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 have arisen from restructuring programmes and represent a combination of credits as a result of the curtailment in the pension arrangements of a number of employees
mostly in the US and charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone. The UK also includes
$12 million of cost resulting from benefit harmonization within the primary plan.

c Most of the contributions made by plan participants into UK pension plans were made under salary sacrifice.
d The benefit payments amount shown above comprises $2,754 million benefits and $14 million settlements, plus $55 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $7,902 million for pension liabilities and $2,631 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree

medical liabilities). The benefit obligation for the Eurozone includes $4,289 million for pension liabilities in Germany which is largely unfunded.

f The actual return on plan assets is made up of the sum of the interest income on plan assets and the remeasurement of plan assets as disclosed above.
g The fair value of plan assets includes borrowings related to the LDI programme as described on page 159.

160

BP Annual Report and Form 20-F 2016

23. Pensions and other post-retirement benefits – continued

Analysis of the amount charged to profit (loss) 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

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 participantsc
Benefit payments (funded plans)d
Benefit payments (unfunded plans)d
Acquisitions
Reclassified as assets held for sale
Remeasurements
Benefit obligation at 31 Decembera e

Movements in fair value of plan assets during the year
Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsa f
Contributions by plan participantsc
Contributions by employers (funded plans)
Benefit payments (funded plans)d
Acquisitions
Remeasurementsf
Fair value of plan assets at 31 Decemberg
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

485
12
–
497

31
528

(1,124)
1,146
22

315
2,054
–
336
2,705

32,416
(1,451)
497
1,146
32
(1,269)
(7)
–
–
(2,390)
28,974

31,773
(1,506)
1,124
32
754
(1,269)
–
315
31,223
2,249

2,516
(267)
2,249

371
(27)
–
344

205
549

(289)
423
134

(139)
607
60
(48)
480

11,875
–
344
423
–
(1,124)
(256)
–
–
(619)
10,643

8,355
–
289
–
129
(1,124)
–
(139)
7,510
(3,133)

66
(3,199)
(3,133)

96
47
(1)
142

8
150

(37)
151
114

25
592
15
47
679

8,327
(843)
142
151
2
(81)
(306)
–
(98)
(654)
6,640

1,973
(205)
37
2
123
(81)
–
25
1,874
(4,766)

25
(4,791)
(4,766)

2,506
(257)
2,249

49
(3,182)
(3,133)

(254)
(4,512)
(4,766)

96
(7)
(3)
86

41
127

(55)
91
36

33
213
–
29
275

2,638
(294)
86
91
5
(178)
(26)
9
–
(242)
2,089

1,735
(186)
55
5
60
(178)
7
33
1,531
(558)

40
(598)
(558)

(187)
(371)
(558)

$ million

2015

Total

1,048
25
(4)
1,069

285
1,354

(1,505)
1,811
306

234
3,466
75
364
4,139

55,256
(2,588)
1,069
1,811
39
(2,652)
(595)
9
(98)
(3,905)
48,346

43,836
(1,897)
1,505
39
1,066
(2,652)
7
234
42,138
(6,208)

2,647
(8,855)
(6,208)

2,114
(8,322)
(6,208)

(28,717)
(257)
(28,974)

(7,461)
(3,182)
(10,643)

(2,128)
(4,512)
(6,640)

(1,718)
(371)
(2,089)

(40,024)
(8,322)
(48,346)

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 have arisen from restructuring programmes and represent a combination of credits as a result of the curtailment in the pension arrangements of a number of employees

mostly in the US and Trinidad and charges for special termination benefits representing the increased liability arising as a result of early retirements mostly in the UK and Eurozone.

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 $3,128 million benefits and $57 million settlements, plus $62 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $8,061 million for pension liabilities and $2,582 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree

medical liabilities). The benefit obligation for the Eurozone includes $4,151 million for pension liabilities in Germany which is largely unfunded.

BP Annual Report and Form 20-F 2016

161

F
n
a
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c
a

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t
a
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s

23. Pensions and other post-retirement benefits – continued

Analysis of the amount charged to profit (loss) 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

Eurozone

Other

494
–
–

494

524

(1,425)
1,378

(47)

356
(33)
(66)

257

214

471

(317)
458

141

72
20
–

103

(70)
255

185

87
1
–

142

(80)
115

$ million

2014

Total

1,009
(12)
(66)

931

309

1,240

(1,892)
2,206

314

1,269

768

119

2,187

liabilities

(3,188)

(1,004)

(1,845)

(350)

(6,387)

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

42
(41)

(1,918)

(264)
13

(487)

(20)
(86)

(9)
(25)

(251)
(139)

(1,832)

(353)

(4,590)

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.

At 31 December 2016, reimbursement balances due from or to other companies in respect of pensions amounted to $28 million reimbursement
assets (2015 $377 million) and $13 million reimbursement liabilities (2015 $13 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 2016 for the group’s plans would have had the effects shown in the table
below. The effects shown for the expense in 2017 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 2017
Effect on pension and other post-retirement benefit obligation at 31 December 2016

Inflation rateb

Effect on pension and other post-retirement benefit expense in 2017
Effect on pension and other post-retirement benefit obligation at 31 December 2016

Salary growth

Effect on pension and other post-retirement benefit expense in 2017
Effect on pension and other post-retirement benefit obligation at 31 December 2016

$ million

One percentage point
Decrease

Increase

(360)
(7,515)

308
9,888

279
5,805

104
1,300

(232)
(5,048)

(91)
(1,165)

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.
b The amounts presented reflect the total impact of an inflation rate change on the assumptions for rate of increase in salaries, pensions in payment and deferred pensions.

One additional year of longevity in the mortality assumptions would increase the 2017 pension and other post-retirement benefit expense by
$55 million and the pension and other post-retirement benefit obligation at 31 December 2016 by $1,558 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 2026 and the
weighted average duration of the defined benefit obligations at 31 December 2016 are as follows:

Estimated future benefit payments

2017
2018
2019
2020
2021
2022-2026

906
949
986
1,005
1,041
5,586

Eurozone

Other

912
889
861
846
848
3,869

341
327
321
309
300
1,420

107
108
111
110
110
561

$ million

Total

2,266
2,273
2,279
2,270
2,299
11,436

Years

Weighted average duration

20.3

9.9

14.9

13.3

162

BP Annual Report and Form 20-F 2016

24. Cash and cash equivalents

Cash
Term bank deposits
Cash equivalents

2016

5,592
15,947
1,945

23,484

$ million

2015

4,653
16,749
4,987

26,389

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 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 2016 includes $2,059 million (2015 $2,439 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 $3,649 million (2015 $4,329 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax
will arise on repatriation.

25. Finance debt

Borrowings
Net obligations under finance leases

Current Non-current

6,592
42

6,634

51,074
592

51,666

2016

Total

57,666
634

58,300

Current

Non-current

6,898
46

6,944

45,567
657

46,224

$ million

2015

Total

52,465
703

53,168

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
$5,587 million (2015 $5,942 million) and issued commercial paper of $971 million (2015 $869 million). Finance debt does not include accrued
interest, which is reported within other payables.

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.

Fixed rate debt

Floating rate debt

Total

US dollar
Other currencies

Weighted
average
interest
rate
%

Weighted
average
time for
which rate
is fixed
Years

3
7

3
6

4
16

4
17

Weighted
average
interest
rate
%

2
1

1
1

Amount
$ million

8,693
809

9,502

10,442
826

11,268

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Amount
$ million

47,749
1,049

48,798

40,623
1,277

41,900

Amount
$ million

2016

56,442
1,858

58,300

2015

51,065
2,103

53,168

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 2016, 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 majority of the group’s long-term borrowings are 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 and such measurements are
therefore categorized in level 2 of the fair value hierarchy. 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 and are consequently
categorized in level 2 of the fair value hierarchy.

Short-term borrowings
Long-term borrowings
Net obligations under finance leases
Total finance debt

2016

Carrying
amount
1,006
56,660
634
58,300

Fair value
956
51,404
1,178
53,538

Fair value
1,006
57,723
1,097
59,826

$ million

2015

Carrying
amount
956
51,509
703
53,168

BP Annual Report and Form 20-F 2016

163

26. 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.

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.

We aim to manage the net debt ratio within a 20-30% band while weak market conditions remain and maintain a significant liquidity buffer. At
31 December 2016, the net debt ratio was 26.8% (2015 21.6%).

At 31 December

Gross debt
Less: fair value asset (liability) of hedges related to finance debta

Less: cash and cash equivalents

Net debt

Equity
Net debt ratio

2016

58,300
(697)

58,997
23,484

35,513

96,843
26.8%

$ million

2015

53,168
(379)

53,547
26,389

27,158

98,387
21.6%

a Derivative financial instruments entered into for the purpose of managing interest rate and foreign currency exchange risk associated with net debt with a fair value liability position of

$1,962 million (2015 liability of $1,617 million) are not included in the calculation of net debt shown above as hedge accounting was not applied for these instruments.

An analysis of changes in net debt is provided below.

Movement in net debt

At 1 January
Exchange adjustments
Net cash flow
Other movements

At 31 December

Finance
debta

(53,547)
80
(5,808)
278

Cash and
cash
equivalents

26,389
(820)
(2,085)
–

2016

Net debt

(27,158)
(740)
(7,893)
278

Finance
debta

(52,409)
1,065
(2,220)
17

Cash and
cash
equivalents

29,763
(672)
(2,702)
–

(58,997)

23,484

(35,513)

(53,547)

26,389

$ million

2015

Net debt

(22,646)
393
(4,922)
17

(27,158)

a Including the fair value of associated derivative financial instruments for which hedge accounting is applied.

27. Operating leases

The cost recognized in relation to minimum lease payments for the year was $5,113 million (2015 $6,008 million and 2014 $6,324 million).

The future minimum lease payments at 31 December 2016, before deducting related rental income from operating sub-leases of $186 million
(2015 $166 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

2016

3,315
6,651
4,289

$ million

2015

4,144
7,743
3,535

14,255

15,422

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 some 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 international oil and gas ships managed by the BP Shipping
function and drilling rigs used in the Upstream segment. At 31 December 2016, the future minimum lease payments relating to these
amounted to $3,582 million (2015 $3,036 million) and $2,969 million (2015 $4,783 million) respectively.

164

BP Annual Report and Form 20-F 2016

27. Operating leases – continued

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.

28. 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 2016

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 2015

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

Loans and
receivables

Note

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

17
17

19
29
24

21
29

17
17

19
29
24

21
29

–
–
791
20,616
–
21,539

–
–
–
–

407
42
–
–
–
1,749

–
–
–
–

–
–
–
–
–
196

–
–

–

42,946

2,198

196

–
–
801
22,214
–
21,402

–
–
–
–

397
219
–
–
–
2,859

–
–
–
–

–
–
–
–
–
2,128

–
–
–
–

44,417

3,475

2,128

–
628
–
–
6,490
–

–
(6,507)
–
–

611

–
605
–
–
7,700
–

–
(6,139)
–
–

2,166

–
–
–
–
885
–

–
–
–
–
–
–

–
(1,997)
–
–

(1,112)

(49,534)
–
(5,605)
(58,300)

(113,439)

–
–
–
–
951
–

–
(1,383)
–
–

(432)

–
–
–
–
–
–

(32,094)
–
(7,151)
(53,168)

(92,413)

407
670
791
20,616
7,375
23,484

(49,534)
(8,504)
(5,605)
(58,300)

(68,600)

397
824
801
22,214
8,651
26,389

(32,094)
(7,522)
(7,151)
(53,168)

(40,659)

The fair value of finance debt is shown in Note 25. 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, LNG 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 control framework
as described more fully below.

BP Annual Report and Form 20-F 2016

165

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28. Financial instruments and financial risk factors – continued

(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.

(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.

(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, Eurozone and Australian operational
requirements, for which hedging programmes are in place and hedge accounting is applied as outlined in Note 1.

For highly probable forecast capital expenditures the group fixes the US dollar cost of non-US dollar supplies by using currency forwards. The
exposures are sterling, euro, Australian dollar and Norwegian krone. At 31 December 2016 the most significant open contracts in place were for
$1,204 million sterling (2015 $627 million sterling).

For other UK, Eurozone 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 2016, the open positions relating to cylinders consisted of receive sterling,
pay US dollar cylinders for $1,885 million (2015 $2,479 million); receive euro, pay US dollar cylinders for $585 million (2015 $560 million); receive
Australian dollar, pay US dollar cylinders for $274 million (2015 $312 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 2016, the total foreign
currency borrowings not swapped into US dollars net of those hedged with cash in the same currency expected to be held until the maturity of
those borrowings amounted to $809 million (2015 $826 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 2016 was 84% of
total finance debt outstanding (2015 79%). The weighted average interest rate on finance debt at 31 December 2016 was 2% (2015 2%) and
the weighted average maturity of fixed rate debt was five years (2015 five 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 2017, it is estimated that the group’s
finance costs for 2017 would increase by approximately $488 million (2015 $419 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 the outstanding exposure incremental to that recognized on the balance sheet at 31 December 2016 was
$309 million (2015 $35 million) in respect of liabilities of joint ventures and associates and $370 million (2015 $163 million) in respect of
liabilities of other third parties.

166

BP Annual Report and Form 20-F 2016

28. Financial instruments and financial risk factors – continued

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.

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 2016, the group had in place credit enhancements
designed to mitigate approximately $11.6 billion of credit risk (2015 $10.9 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.

Management information used to monitor credit risk indicates that 79% (2015 81%) of total unmitigated credit exposure relates to
counterparties 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

2016

19,459
71

446
116
56
468

$ million

2015

21,064
22

414
75
118
521

20,616

22,214

Movements in the impairment provision for trade receivables are shown in Note 20.

Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements
The following table shows the amounts recognized for financial assets and liabilities which are subject to offsetting arrangements on a gross
basis, 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 presented in the table to show the total net exposure of the group.

At 31 December 2016

Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
At 31 December 2015

Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables

Gross
amounts of
recognized
financial
assets
(liabilities)

9,025
(10,236)
8,815
(9,664)

10,206
(9,280)
7,091
(5,720)

Amounts
set off

(1,882)
1,882
(4,468)
4,468

(1,859)
1,859
(3,689)
3,689

Related amounts not set off
in the balance sheet

Net amounts
presented on
the balance
sheet

Master
netting
arrangements

Cash
collateral
(received)
pledged

7,143
(8,354)
4,347
(5,196)

8,347
(7,421)
3,402
(2,031)

(1,058)
1,058
(1,039)
1,039

(1,109)
1,109
(322)
322

(133)
–
(118)
–

(297)
–
(161)
–

$ million

Net amount

5,952
(7,296)
3,190
(4,157)

6,941
(6,312)
2,919
(1,709)

(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, generally subsidiaries pool their cash surpluses to the treasury function, 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 Ratings long-term credit rating for BP is A negative (stable outlook) and Moody’s Investors Service rating is A2 (positive
outlook).

During 2016, $12 billion of long-term taxable bonds were issued with terms ranging from three to twelve 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 $23.5 billion at
31 December 2016 (2015 $26.4 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate
and short notice. At 31 December 2016, 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 2017. These facilities are 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 $6,750 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 2016 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.

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28. 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
payablesa

35,774
2,005
1,278
1,239
1,229
5,826
7,248

54,599

Accruals

5,136
186
91
53
33
75
31

5,605

Finance
debt

6,634
5,973
6,734
6,301
6,780
22,378
3,500

58,300

2016

Interest

1,217
1,083
942
801
658
1,843
816

7,360

Trade and
other
payablesa

29,743
971
1,231
56
17
38
38

32,094

Accruals

6,261
380
138
98
74
167
33

7,151

Finance
debt

6,944
5,796
6,208
6,103
6,354
17,651
4,112

53,168

$ million

2015

Interest

928
812
704
592
478
1,068
402

4,984

a 2016 includes $21,644 million and 2015 includes $2,750 million in relation to Gulf of Mexico oil spill.

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 29. 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 the timing of cash outflows for derivative financial instruments entered into for the purpose of managing interest rate
and foreign currency exchange risk associated with net debt, whether or not hedge accounting is applied, based upon contractual payment
dates. The amounts reflect 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 $18,014 million at 31 December 2016 (2015
$15,706 million) to be received on the same day as the related cash outflows. For further information on our derivative financial instruments,
see Note 29.

Cash outflows for derivative financial instruments at 31 December

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

2016

2,677
1,505
1,700
1,678
2,384
9,985
1,413

$ million

2015

2,959
2,685
1,505
1,700
1,678
5,500
2,739

21,342

18,766

29. 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 28. 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.

168

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29. 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
Other embedded derivatives

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

Fair value
asset

2016

Fair value
liability

167
1,543
3,780
768
232

6,490

–
–

–

32
–

22
831

853

7,375

3,016
4,359

(2,000)
(952)
(2,845)
(560)
–

(6,357)

(50)
(100)

(150)

(451)
(154)

(605)

(1,159)
(233)

(1,392)

(8,504)

(2,991)
(5,513)

Fair value
asset

144
2,390
3,942
920
292

7,688

12
–

9
–

33
909

942

8,651

4,242
4,409

$ million

2015

Fair value
liability

(1,811)
(1,257)
(2,536)
(434)
–

(6,038)

(101)
–

(101)

(71)
(147)

(218)

(1,108)
(57)

(1,165)

(7,522)

(3,239)
(4,283)

F
n
a
n
c
a

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 28.

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.

s
t
a
t
e
m
e
n
t
s

Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives

Less than
1 year

102
1,178
1,238
305
132

2,955

Less than
1 year

132
1,729
1,707
459
182
4,209

1-2 years

2-3 years

3-4 years

4-5 years

34
201
647
164
–

1,046

20
91
424
114
–

649

2
49
313
58
–

422

7
22
267
53
–

349

1-2 years

2-3 years

3-4 years

4-5 years

10
432
639
164
110
1,355

1
130
390
103
–
624

1
58
283
79
–
421

–
37
202
47
–
286

$ million

2016

Total

167
1,543
3,780
768
232

6,490

$ million

2015

Total

144
2,390
3,942
920
292
7,688

Over
5 years

2
2
891
74
100

1,069

Over
5 years

–
4
721
68
–
793

At 31 December 2016 and 2015 the group had contingent consideration receivable in respect of the disposal of the Texas City refinery. 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.

BP Annual Report and Form 20-F 2016

169

29. 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

(379)
(787)
(947)
(201)

(2,314)

Less than
1 year

(499)
(1,053)
(1,037)
(246)

(2,835)

1-2 years

2-3 years

3-4 years

4-5 years

(36)
(105)
(421)
(126)

(688)

(402)
(40)
(257)
(81)

(780)

(101)
(11)
(258)
(39)

(409)

(338)
(3)
(197)
(31)

(569)

1-2 years

2-3 years

3-4 years

4-5 years

(2)
(163)
(382)
(70)

(617)

(2)
(26)
(210)
(31)

(269)

(347)
(10)
(146)
(34)

(537)

(79)
(2)
(162)
(17)

(260)

Over
5 years

(744)
(6)
(765)
(82)

(1,597)

Over
5 years

(882)
(3)
(599)
(36)

(1,520)

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.

Less than
1 year

3,962
448

4,410
(1,455)

2,955

(3,610)
(159)

(3,769)
1,455

(2,314)

641

Less than
1 year

109
4,946
684

5,739
(1,530)

4,209

(104)
(4,083)
(178)

(4,365)
1,530
(2,835)
1,374

1-2 years

2-3 years

3-4 years

4-5 years

1,035
265

1,300
(254)

1,046

(778)
(164)

(942)
254

(688)

358

509
249

758
(109)

649

(701)
(188)

(889)
109

(780)

(131)

208
243

451
(29)

422

(249)
(189)

(438)
29

(409)

117
241

358
(9)

349

(401)
(177)

(578)
9

(569)

(220)

1-2 years

2-3 years

3-4 years

4-5 years

–
1,137
449

1,586
(231)

1,355

–
(700)
(148)

(848)
231
(617)
738

–
402
271

673
(49)

624

–
(177)
(141)

(318)
49
(269)
355

–
213
240

453
(32)

421

–
(423)
(146)

(569)
32
(537)
(116)

–
68
230

298
(12)

286

–
(124)
(148)

(272)
12
(260)
26

Over
5 years

189
906

1,095
(26)

1,069

(872)
(751)

(1,623)
26

(1,597)

(528)

Over
5 years

–
50
748

798
(5)

793

–
(889)
(636)

(1,525)
5
(1,520)
(727)

Fair value of derivative assets

Level 2
Level 3

Less: netting by counterparty

Fair value of derivative liabilities

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

170

BP Annual Report and Form 20-F 2016

$ million

2016

Total

(2,000)
(952)
(2,845)
(560)

(6,357)

$ million

2015

Total

(1,811)
(1,257)
(2,536)
(434)

(6,038)

$ million

2016

Total

6,020
2,352

8,372
(1,882)

6,490

(6,611)
(1,628)

(8,239)
1,882

(6,357)

133

$ million

2015

Total

109
6,816
2,622

9,547
(1,859)

7,688

(104)
(6,396)
(1,397)

(7,897)
1,859
(6,038)
1,650

29. 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.

Fair value of contracts at 1 January 2016
Gains (losses) recognized in the income statement
Settlements
Transfers out of level 3

Net fair value of contracts at 31 December 2016

Deferred day-one gains (losses)

Derivative asset (liability)

Fair value of contracts at 1 January 2015
Gains (losses) recognized in the income statement
Settlements
Transfers out of level 3

Net fair value of contracts at 31 December 2015

Deferred day-one gains (losses)

Derivative asset (liability)

Oil
price

169
(37)
(63)
(1)

Oil
price

146
44
(20)
(1)

169

Natural gas
price

214
1
(51)
(19)

145

Natural gas
price

74
288
(40)
(108)

214

Power
price

91
(82)
(145)
(11)

(147)

Power
price

109
76
(72)
(22)

Other

292
139
(200)
–

231

Other

389
92
(189)
–

292

$ million

Total

766
21
(459)
(31)

297

427

724

$ million

Total

718
500
(321)
(131)

766

459

1,225

The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2016 was a
$253-million loss (2015 $293-million gain related to derivatives still held at 31 December 2015).

Derivative gains and losses
Gains and losses relating to derivative contracts are included within sales and other operating revenues 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 $1,435 million (2015 $5,508 million net gain and 2014 $6,154 million net gain). 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 has embedded derivatives relating to certain natural gas contracts. The fair value gain on commodity price embedded derivatives
included within distribution and administration expenses was a gain of $32 million (2015 gain of $120 million, 2014 gain of $430 million).

Cash flow hedges
At 31 December 2016, the group held currency forwards, futures contracts and cylinders and cross-currency interest rate swaps that were being
used to hedge the foreign currency risk of highly probable forecast transactions and floating rate finance debt. Note 28 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 2016 in relation to these cash flow hedges consist of deferred losses of $343 million maturing in 2017, deferred losses of
$71 million maturing in 2018 and deferred losses of $22 million maturing in 2019 and beyond.

Fair value hedges
At 31 December 2016, 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 2016 was
$316 million (2015 $788 million loss and 2014 $14 million loss) offset by a gain on the fair value of the finance debt of $270 million (2015
$833 million gain and 2014 $8 million gain).

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 28 outlines the group’s approach to interest rate and foreign currency exchange
risk management.

BP Annual Report and Form 20-F 2016

171

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

30. 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

Issue of new shares – otherc
Repurchase of ordinary share capitald

At 31 December

Shares
thousand

7,233
5,473

2016

$ million

12
9

Shares
thousand

7,233
5,473

2015

$ million

12
9

Shares
thousand

7,233
5,473

20,108,771
548,005

5,028
137

20,005,961
102,810

5,002
26

20,426,632
165,644

–
392,920
–

21,049,696

–
–
–

20,108,771

–
98
–

5,263

5,284

–
–
–

5,028

5,049

25,598
–
(611,913)

20,005,961

2014

$ million

12
9

5,108
41

6
–
(153)

5,002

5,023

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 in 2014.
c Relates to the issue of new ordinary shares in consideration for a 10% interest in the Abu Dhabi onshore oil concession. See Note 31 for further information.
d In 2014 shares were repurchased for a total consideration of $4,796 million, including transaction costs of $26 million. All shares purchased were for cancellation.

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.

Treasury sharesa

At 1 January
Purchases for settlement of employee share plans
Shares re-issued for employee share-based payment plans

At 31 December

Of which – shares held in treasury by BP

– shares held in ESOP trusts
– shares held by BP’s US share plan administratorb

2016

2015

2014

Shares
thousand

Nominal value
$ million

Shares
thousand

Nominal value
$ million

Shares
thousand

Nominal value
$ million

1,756,327
9,631
(151,339)

1,614,619

1,576,411
21,432
16,814

439 1,811,297
51,142
(106,112)

2
(38)

453 1,833,544
49,559
(71,806)

13
(27)

403 1,756,327

439 1,811,297

394 1,727,763
18,453
10,111

5
4

432 1,771,103
34,169
6,025

4
3

458
12
(17)

453

443
9
1

a See Note 31 for definition of treasury shares.
b Held in the form of ADSs to meet the requirements of employee share-based payment plans in the US.

For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year,
representing 8.6% (2015 8.9% and 2014 8.8%) of the called-up ordinary share capital of the company.

During 2016, the movement in shares held in treasury by BP represented less than 0.8% (2015 less than 0.2% and 2014 less than 0.1%) of the
ordinary share capital of the company.

172

BP Annual Report and Form 20-F 2016

F
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a
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a

THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY

s
t
a
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e
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BP Annual Report and Form 20-F 2016

173

31. Capital and reserves

At 1 January 2016
Profit (loss) 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 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

Total comprehensive income
Dividends
Share-based payments, net of taxb c
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2016

At 1 January 2015
Profit (loss) for the year
Items that may be reclassified subsequently to profit or loss

Currency translation differences (including recycling)a
Available-for-sale investments (including recycling)
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
Share-based payments, net of taxc
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2015

At 1 January 2014
Profit (loss) 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 taxd
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2014

Share
capital
5,049
–

Share
premium
account
10,234
–

Capital
redemption
reserve
1,413
–

Total
share capital
and capital
reserves
43,902
–

Merger
reserve
27,206
–

–
–
–
–
–

–
–
137
98
–
–
5,284

Share
capital
5,023
–

–
–
–
–
–

–
–
–
26
–
–
–
5,049

Share
capital
5,129
–

–
–
–
–

–
–
–
41
(153)
6
–
–
5,023

–
–
–
–
–

–
–
(137)
2,122
–
–
12,219

–
–
–
–
–

–
–
–
–
–
–
1,413

Share
premium
account
10,260
–

Capital
redemption
reserve
1,413
–

–
–
–
–
–

–
–
–
(26)
–
–
–
10,234

–
–
–
–
–

–
–
–
–
–
–
–
1,413

Share
premium
account
10,061
–

Capital
redemption
reserve
1,260
–

–
–
–
–

–
–
–
(41)
–
240
–
–
10,260

–
–
–
–

–
–
–
–
153
–
–
–
1,413

–
–
–
–
–

–
–
–
–
–
–
27,206

Merger
reserve
27,206
–

–
–
–
–
–

–
–
–
–
–
–
–
27,206

Merger
reserve
27,206
–

–
–
–
–

–
–
–
–
–
–
–
–
27,206

–
–
–
–
–

–
–
–
2,220
–
–
46,122

Total
share capital
and capital
reserves
43,902
–

–
–
–
–
–

–
–
–
–
–
–
–
43,902

Total
share capital
and capital
reserves
43,656
–

–
–
–
–

–
–
–
–
–
246
–
–
43,902

a Principally foreign exchange effects relating to the Russian rouble.
b Includes ordinary shares issued to the government of Abu Dhabi in consideration for a 10% interest in the Abu Dhabi onshore oil concession. The share-based payment transaction was valued

at the fair value of the interest in the assets, with reference to a market transaction for an identical interest.

c Movements in treasury shares relate to employee share-based payment plans.
d New share issues and movements in treasury shares relate to employee share-based payment plans.

174

BP Annual Report and Form 20-F 2016

Treasury
shares
(19,964)
–

–
–
–
–
–

–
–
–
1,521
–
–
(18,443)

Treasury
shares
(20,719)
–

–
–
–
–
–

–
–
–
–
755
–
–
(19,964)

Treasury
shares
(20,971)
–

–
–
–
–

–
–
–
–
–
252
–
–
(20,719)

Foreign
currency
translation
reserve
(7,267)
–

Available-
for-sale
investments
2
–

Cash flow
hedges
(825)
–

–
–
(331)
–
–

–
(331)
–
–
–
–
(1,156)

Cash flow
hedges
(898)
–

–
–
73
–
–

–
–
73
–
–
–
–
(825)

Total
fair value
reserves
(823)
–

–
1
(331)
–
–

–
(330)
–
–
–
–
(1,153)

Total
fair value
reserves
(897)
–

–
1
73
–
–

–
–
74
–
–
–
–
(823)

Profit and
loss
account
81,368
115

BP
shareholders’
equity
97,216
115

Non-
controlling
interests
1,171
57

–
–
–
833
(96)

(1,757)
(905)
(4,611)
(750)
106
430
75,638

389
1
(331)
833
(96)

(1,757)
(846)
(4,611)
2,991
106
430
95,286

(27)
–
–
–
–

–
30
(107)
–
–
463
1,557

Profit and
loss
account
92,564
(6,482)

BP
shareholders’
equity
111,441
(6,482)

Non-
controlling
interests
1,201
82

–
–
–
(814)
80

2,742
(1)
(4,475)
(6,659)
(99)
40
(3)
81,368

(3,858)
1
73
(814)
80

2,742
(1)
(8,259)
(6,659)
656
40
(3)
97,216

(41)
–
–
–
–

–
–
41
(91)
–
–
20
1,171

–
1
–
–
–

–
1
–
–
–
–
3

Available-
for-sale
investments
1
–

–
1
–
–
–

–
–
1
–
–
–
–
2

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

1
–
–
–

–
–
1
–
–
–
–
–
1

–
(203)
–
–

–
–
(203)
–
–
–
–
–
(898)

1
(203)
–
–

–
–
(202)
–
–
–
–
–
(897)

–
–
(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

389
–
–
–
–

–
389
–
–
–
–
(6,878)

Foreign
currency
translation
reserve
(3,409)
–

(3,858)
–
–
–
–

–
–
(3,858)
–
–
–
–
(7,267)

Foreign
currency
translation
reserve
3,525
–

(6,934)
–
–
–

–
–
(6,934)
–
–
–
–
–
(3,409)

$ million

Total equity
98,387
172

362
1
(331)
833
(96)

(1,757)
(816)
(4,718)
2,991
106
893
96,843

Total equity
112,642
(6,400)

(3,899)
1
73
(814)
80

2,742
(1)
(8,218)
(6,750)
656
40
17
98,387

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

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31. 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) and BP’s US share plan administrator 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.

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. It
includes $651 million relating to the acquisition of an 18.5% interest in Rosneft in 2013 which will only be reclassified to the income statement if
the investment in Rosneft is either sold or impaired. For further information on the accounting for cash flow hedges 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.

176

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31. 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

Items that will not be reclassified to profit or loss

Remeasurements of the net pension and other post-retirement benefit liability or asset

Other comprehensive income

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

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

32. Contingent liabilities

$ million

2016

Pre-tax

Tax

Net of tax

284
1
(362)
833
–

(2,496)

(1,740)

78
–
31
–
(96)

739

752

362
1
(331)
833
(96)

(1,757)

(988)

$ million

2015

Pre-tax

Tax

Net of tax

(4,096)
1
93
(814)
–

4,139
(1)

(678)

197
–
(20)
–
80

(1,397)
–

(1,140)

(3,899)
1
73
(814)
80

2,742
(1)

(1,818)

$ million

2014

Pre-tax

Tax

Net of tax

(6,787)
(239)
(2,584)
–

(4,590)
4

(14,196)

(178)
36
–
289

(6,965)
(203)
(2,584)
289

1,334
–

1,481

(3,256)
4

(12,715)

Contingent liabilities related to the Gulf of Mexico oil spill
See Note 2 for information on contingent liabilities related to the Gulf of Mexico oil spill.

Contingent liabilities not related to the Gulf of Mexico oil spill
There were contingent liabilities at 31 December 2016 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 on financial guarantees is included
in Note 28.

In the normal course of the group’s business, legal proceedings are pending or may be brought against BP group entities arising out of current
and past operations, including matters related to commercial disputes, product liability, antitrust, commodities trading, premises-liability claims,
consumer protection, general environmental claims and allegations of exposures of third parties to toxic substances, such as lead pigment in
paint, asbestos and other chemicals. BP believes that the impact of these legal proceedings on the group‘s results of operations, liquidity or
financial position will not be material.

With respect to lead pigment in paint in particular, Atlantic Richfield, a subsidiary of BP, has been named as a co-defendant in numerous lawsuits
brought in the US alleging injury to persons and property. Although it is not possible to predict the outcome of the legal proceedings, Atlantic
Richfield believes it has valid defences that render the incurrence of a liability remote; however, the amounts claimed and the costs of
implementing the remedies sought in the various cases could be substantial. The majority of the lawsuits have been abandoned or dismissed
against Atlantic Richfield. No lawsuit against Atlantic Richfield has been settled nor has Atlantic Richfield been subject to a final adverse
judgment in any proceeding. Atlantic Richfield intends to defend such actions vigorously.

The group files tax returns in many jurisdictions throughout the world. Various tax authorities are currently examining the group’s tax returns. Tax
returns contain matters that could be subject to differing interpretations of applicable tax laws and regulations and the resolution of tax positions
through negotiations with relevant tax authorities, or through litigation, can take several years to complete. While it is difficult to predict the
ultimate outcome in some cases, the group does not anticipate that there will be any material impact upon the group‘s results of operations,
financial position or liquidity.

BP Annual Report and Form 20-F 2016

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32. Contingent liabilities – continued

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. BP is
not currently aware of any such cases that have a greater than remote chance of reverting to the Group. Furthermore, as described in Provisions
and contingencies 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.

33. Remuneration of senior management and non-executive directors

Remuneration of directors

Total for all directors

Emoluments
Amounts received under incentive schemesa

Total

a Excludes amounts relating to past directors.

2016

2015

10
14

$ million

2014

14
10

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.

Pension contributions
During 2016 one executive director 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 executive director participated in 2016 in a US defined benefit pension plan
and retirement savings plans established for US employees.

Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 80.

Remuneration of directors and senior management

Total for all senior management and non-executive directors

Short-term employee benefits
Pensions and other post-retirement benefits
Share-based payments

Total

2016

2015

28
3
39

33
4
36

$ million

2014

34
3
34

Senior management comprises members of the executive team, see pages 58-59 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 $2.2 million in 2016 (2015 $nil and 2014 $1.5 million).

Pensions and other post-retirement benefits
The amounts represent the estimated cost to the group of providing 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’.

178

BP Annual Report and Form 20-F 2016

34. Employee costs and numbers

Employee costs

Wages and salariesa
Social security costs
Share-based paymentsb
Pension and other post-retirement benefit costs

Average number of employeesc

Non-US

Upstream
Downstreamd e
Other businesses and corporatee f

6,700
6,600
1,900

15,200

13,500
36,600
12,100

62,200

2016

Total

20,200
43,200
14,000

77,400

Non-US

7,900
7,800
1,700

17,400

15,100
38,200
11,900

65,200

2015

Total

23,000
46,000
13,600

82,600

2016

8,456
760
764
1,253

2015

9,556
879
833
1,660

11,233

12,928

Non-US

9,100
8,200
1,800

19,100

15,600
39,900
10,100

65,600

$ million

2014

10,710
983
689
1,554

13,936

2014

Total

24,700
48,100
11,900

84,700

a Includes termination payments of $545 million (2015 $857 million and 2014 $527 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 15,800 (2015 15,000 and 2014 14,200) service station staff.
e Around 800 centralized function employees were reallocated from Upstream and Downstream to Other businesses and corporate during 2016, and around 2,000 employees from the global

business services organization were reallocated from Downstream to Other businesses and corporate during 2015.

f Includes 4,900 (2015 5,300 and 2014 5,100) agricultural, operational and seasonal workers in Brazil.

35. Auditor’s remuneration

Fees – Ernst & Young

The audit of the company annual accountsa
The audit of accounts of 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
Total non-audit and other assurance services

Total non-audit or non-audit-related assurance services

Services relating to BP pension plansc

2016

2015

$ million

2014

25
12

37
7

1
–
–
1

27
13

40
7

1
–
1
1

27
13

40
7

1
1
1
2

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 service of $nil (2015 $0.4 million and 2014 $0.4 million).

2016 includes $1 million of additional fees for 2015 and 2015 includes $2 million of additional fees for 2014. 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 $47 million (2015 $51 million and 2014 $53 million) is required to be presented as
follows: audit $37 million (2015 $40 million and 2014 $40 million); other audit-related $7 million (2015 $7 million and 2014 $7 million); tax
$1 million (2015 $1 million and 2014 $2 million); and all other fees $2 million (2015 $3 million and 2014 $4 million).

BP Annual Report and Form 20-F 2016

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36. Subsidiaries, joint arrangements and associates

The more important subsidiaries and associates of the group at 31 December 2016 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 undertakings of the
group is included in Note 14 in the parent company financial statements of BP p.l.c. which are filed with the Registrar of Companies in the UK,
along with the group’s annual report.

Subsidiaries

International

BP Corporate Holdings
BP Exploration Operating Company

*BP Global Investments
*BP International

BP Oil International

*Burmah Castrol

Angola

BP Exploration (Angola)

Azerbaijan

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

100

England & Wales

Exploration and production

BP Exploration (Caspian Sea)
BP Exploration (Azerbaijan)

100
100

England & Wales
England & Wales

Exploration and production
Exploration and production

Canada

*BP Holdings Canada

Egypt

BP Exploration (Delta)

Germany

BP Europa SE

India

BP Exploration (Alpha)

Trinidad & Tobago

BP Trinidad and Tobago

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

England & Wales

Investment holding

100

England & Wales

Exploration and production

100

Germany

Refining and marketing

100

England & Wales

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

180

BP Annual Report and Form 20-F 2016

37. 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. Non-current assets for BP p.l.c. includes 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. incorporates subsidiaries of BP Exploration (Alaska) Inc. using the equity method of accounting
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

Profit (loss) before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and other post-

retirement benefits

Profit (loss) before taxation
Taxation

Profit (loss) for the year

Attributable to

BP shareholders
Non-controlling interests

Statement of comprehensive income

For the year ended 31 December

Profit (loss) 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

2,740
–
–
–
94
–

2,834
888
1,171
102
673
(147)
–
–

147
103

–

44
(41)

85
–

–
–
–
862
343
–

1,205
–
–
–
–
–
–
808

397
311

(82)

168
53

115

115
–

115

182,999
966
994
–
899
1,132

186,990
134,062
27,906
581
13,832
(1,517)
1,721
9,797

608
1,981

272

(1,645)
(2,479)

834

777
57

834

(2,731)
–
–
(862)
(830)
–

(4,423)
(2,731)
–
–
–
–
–
(110)

(1,582)
(720)

–

(862)
–

(862)

(862)
–

(862)

$ million

2016

BP group

183,008
966
994
–
506
1,132

186,606
132,219
29,077
683
14,505
(1,664)
1,721
10,495

(430)
1,675

190

(2,295)
(2,467)

172

115
57

172

$ million

2016

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

–

85
–

BP p.l.c.

115

(1,505)

544

(846)

(846)
–

(846)

Other
subsidiaries

Eliminations and
reclassifications

BP group

834

517

–

1,351

1,321
30

1,351

(862)

–

(544)

(1,406)

(1,406)
–

(1,406)

172

(988)

–

(816)

(846)
30

(816)

BP Annual Report and Form 20-F 2016

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37. Condensed consolidating information on certain US subsidiaries – continued

Income statement continued

For the year ended 31 December

Profit (loss) before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and other post-

retirement benefits

Profit (loss) before taxation
Taxation

Profit (loss) for the year

Attributable to

BP shareholders
Non-controlling interests

a Minor amendments have been made to previously reported amounts.

Statement of comprehensive income continued

For the year ended 31 December

Profit (loss) 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. a

3,438
–
–
–
29
–

3,467
1,432
1,360
140
569
176
–
56

(266)
35

–

(301)
(129)

(172)

(172)
–

(172)

BP p.l.c.

–
–
–
(5,404)
185
31

(5,188)
–
–
–
–
–
–
1,125

(6,313)
36

(6,369)
82

(6,451)

(6,451)
–

(6,451)

Other
subsidiaries

Eliminations and
reclassifications

222,881
(28)
1,839
–
671
666

226,029
166,783
35,680
896
14,650
1,733
2,353
10,449

(6,515)
1,473

286

(8,274)
(3,124)

(5,150)

(5,232)
82

(5,150)

(3,425)
–
–
5,404
(274)
(31)

1,674
(3,425)
–
–
–
–
–
(77)

5,176
(197)

–

5,373
–

5,373

5,373
–

5,373

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

(172)

–

(172)

(172)
–

(172)

BP p.l.c.

(6,451)

1,863

(3,640)

(8,228)

(8,228)
–

(8,228)

Other
subsidiaries

Eliminations and
reclassifications

(5,150)

(3,681)

–

(8,831)

(8,872)
41

(8,831)

5,373

–

3,640

9,013

9,013
–

9,013

$ million

2015

BP group

222,894
(28)
1,839
–
611
666

225,982
164,790
37,040
1,036
15,219
1,909
2,353
11,553

(7,918)
1,347

306

(9,571)
(3,171)

(6,400)

(6,482)
82

(6,400)

$ million

2015

BP group

(6,400)

(1,818)

–

(8,218)

(8,259)
41

(8,218)

182

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37. Condensed consolidating information on certain US subsidiaries – continued

Income statement continued

For the year ended 31 December

Profit (loss) before interest and taxation
Finance costs
Net finance (income) expense relating to pensions and other post-

retirement benefits

Profit (loss) before taxation
Taxation

Profit (loss) for the year

Attributable to

BP shareholders
Non-controlling interests

Statement of comprehensive income continued

For the year ended 31 December

Profit (loss) 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.

6,227
–
–
–
2
19

6,248
2,375
1,779
554
545
153
–
48

794
57

–

737
279

458

458
–

458

BP p.l.c.

–
–
–
4,531
193
–

4,724
–
–
–
–
–
–
929

3,795
23

(50)

3,822
42

3,780

3,780
–

3,780

Other
subsidiaries

Eliminations and
reclassifications

353,529
570
2,802
–
910
876

358,687
285,720
25,596
2,404
14,618
8,812
3,632
11,364

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)

$ 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
12,266

6,412
1,148

314

4,950
947

4,003

3,780
223

4,003

$ million

2014

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

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 2016

183

37. 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

184

BP Annual Report and Form 20-F 2016

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

BP p.l.c.

Other
subsidiaries

Eliminations and
reclassifications

BP group

$ million

2016

7,405
–
578
–
–
–
–

7,983
9
–
–
–
–
–

7,992

–
249
2,583
–
7
–
–
–

2,839

–
–
–
–
2
–
156,864

156,866
–
2,951
–
–
–
528

160,345

–
–
487
–
–
–
–
50

537

122,352
11,194
17,605
8,609
14,090
1,033
–

174,883
34,941
1,474
4,359
945
4,741
56

221,399

259
17,406
24,660
3,016
1,479
1,194
44
23,434

71,492

–
–
–
–
–
–
(156,864)

(156,864)
(34,418)
(2,951)
–
–
–
–

129,757
11,194
18,183
8,609
14,092
1,033
–

182,868
532
1,474
4,359
945
4,741
584

(194,233)

195,503

–
–
(7,055)
–
–
–
–
–

(7,055)

259
17,655
20,675
3,016
1,486
1,194
44
23,484

67,813

10,831

160,882

292,891

(201,288)

263,316

722
–
116
–
11
2

851

20
–
–
–
1,279
1,390

–

2,689

3,540

7,291

7,291
–

7,291

4,096
–
129
–
–
–

4,225

34,389
–
43
–
179
–

219

34,830

39,055

121,827

121,827
–

121,827

40,152
2,991
4,891
6,634
1,655
4,010

60,333

16,906
5,513
426
51,666
5,780
19,022

8,656

107,969

168,302

124,589

123,032
1,557

124,589

(7,055)
–
–
–
–
–

(7,055)

(37,369)
–
–
–
–
–

37,915
2,991
5,136
6,634
1,666
4,012

58,354

13,946
5,513
469
51,666
7,238
20,412

–

8,875

(37,369)

108,119

(44,424)

166,473

(156,864)

96,843

(156,864)
–

(156,864)

95,286
1,557

96,843

37. Condensed consolidating information on certain US subsidiaries – continued

Balance sheet continued

At 31 December

Non-current assets

Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Subsidiaries – equity-accounted basis

Fixed assets
Loans
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses

Current assets

Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents

Assets classified as held for sale

Total assets

Current liabilities

Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions

Liabilities directly associated with assets classified as held for sale

Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan

deficits

Total liabilities

Net assets
Equity

BP shareholders’ equity
Non-controlling interests

a Minor amendments have been made to previously reported amounts.

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.a

BP p.l.c.

Other
subsidiaries

Eliminations and
reclassifications

BP group

$ million

2015

8,345
–
539
–
–
–
–

8,884
3
–
–
4
–
–

8,891

–
246
9,718
–
7
–
–
–

9,971

–

–
–
–
–
2
–
128,234

128,236
–
–
–
–
–
2,516

130,752

–
–
1,062
–
–
–
–
–

1,062

–

121,413
11,627
18,121
8,412
9,420
1,002
–

169,995
7,245
2,216
4,409
999
1,545
131

186,540

272
13,896
22,393
4,242
1,831
599
219
26,389

69,841

578

–
–
–
–
–
–
(128,234)

(128,234)
(6,719)
–
–
–
–
–

129,758
11,627
18,660
8,412
9,422
1,002
–

178,881
529
2,216
4,409
1,003
1,545
2,647

(134,953)

191,230

–
–
(10,850)
–
–
–
–
–

(10,850)

–

272
14,142
22,323
4,242
1,838
599
219
26,389

70,024

578

9,971

1,062

70,419

(10,850)

70,602

18,862

131,814

256,959

(145,803)

261,832

961
–
116
–
(21)
1

1,057

–

1,057

8
–
–
–
1,255
2,326

–

3,589

4,646

127
–
81
–
4
–

212

–

212

6,708
–
33
–
877
–

227

7,845

8,057

14,216

123,757

14,216
–
14,216

123,757
–
123,757

41,711
3,239
6,064
6,944
1,097
5,153

64,208

64,305

2,913
4,283
857
46,224
7,467
33,634

8,628

104,006

168,311

88,648

87,477
1,171
88,648

(10,850)
–
–
–
–
–

(10,850)

–

31,949
3,239
6,261
6,944
1,080
5,154

54,627

(10,850)

54,724

(6,719)
–
–
–
–
–

2,910
4,283
890
46,224
9,599
35,960

–

8,855

(6,719)

108,721

(17,569)

163,445

(128,234)

98,387

(128,234)
–
(128,234)

97,216
1,171
98,387

BP Annual Report and Form 20-F 2016

185

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

37. 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 provided by (used in) investing activities
Net cash provided by (used in) financing activities
Currency translation differences relating to cash and cash equivalents

Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year

Cash and cash equivalents at end of year

For the year ended 31 December

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

Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of year

Cash and cash equivalents at end of year

Issuer

Guarantor

BP
Exploration
(Alaska) Inc.

699
(699)
–
–

–
–

–

BP p.l.c.

4,661
–
(4,611)
–

50
–

Other
subsidiaries

5,331
(14,054)
6,588
(820)

(2,955)
26,389

23,434

Issuer

Guarantor

BP
Exploration
(Alaska)
Inc.

925
(925)
–
–

–
–

–

BP p.l.c.

6,628
–
(6,659)
–

(31)
31

–

Other
subsidiaries

11,580
(16,375)
2,124
(672)

(3,343)
29,732

26,389

Issuer

Guarantor

BP
Exploration
(Alaska)
Inc.

92
(92)
–
–

–
–

–

BP p.l.c.

10,464
–
(10,439)
–

25
6

Other
subsidiaries

22,198
(19,482)
5,173
(671)

7,218
22,514

29,732

$ million

2016

BP group

10,691
(14,753)
1,977
(820)

(2,905)
26,389

23,484

$ million

2015

BP group

19,133
(17,300)
(4,535)
(672)

(3,374)
29,763

26,389

$ million

2014

BP group

32,754
(19,574)
(5,266)
(671)

7,243
22,520

29,763

186

BP Annual Report and Form 20-F 2016

Supplementary information on oil and natural gas (unaudited)
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 251-256.

BP Annual Report and Form 20-F 2016

187

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

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

2016

Total

Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation
Net capitalized costs

34,171
483
34,654
21,745
12,909

Costs incurred for the year ended 31 Decembera b
Acquisition of propertiesc

Proved
Unproved

Exploration and appraisal costsd
Development
Total costs

215
–
215
165
1,284
1,664

–
–
–
–
–

–
–
–
5
3
8

Results of operations for the year ended 31 Decembera
Sales and other operating revenuese

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and

amortization

Net impairments and (gains) losses
on sale of businesses and fixed
assets

Profit (loss) before taxationg
Allocable taxesh
Results of operations

81,633
4,712
86,345
44,988
41,357

3,622
2,377
5,999
272
5,727

12,624
2,450
15,074
6,764
8,310

46,892
3,808
50,700
31,456
19,244

–
–
–
–
–

30,870
4,132
35,002
15,942
19,060

5,752
562
6,314
2,826
3,488

215,564
18,524
234,088
123,993
110,095

314
38
352
391
2,372
3,115

640
6,204
6,844
693
2,524
155
1,687

–
10
10
70
28
108

74
2
76
61
114
–
25

–
10
10
123
1,519
1,652

747
103
850
672
476
38
115

–
181
181
297
2,957
3,435

1,215
3,391
4,606
87
1,220
–
597

–
–
–
10
–
10

–
–
–
10
–
–
34

703
1,728
2,431
252
2,788
5,471

97
3,908
4,005
(27)
691
800
115

207
–
207
89
194
490

1,439
1,967
3,406
1,402
11,145
15,953

1,042
309
1,351
89
154
41
153

4,085
15,725
19,810
1,721
6,006
683
2,548

591

2,937

–

2,179

289

11,213

244
1,387
1,631
133
619
(351)
(215)

26
421
447
3
208
–
37

1,002

209

3,940

(809)
379
1,252
(286)
1,538

(345)
112
335
(287)
622

(627)
8,372
(1,528)
(402)
(1,126)

(5)
261
(185)
(40)
(145)

(77)
1,815
(965)
(194)
(771)

(765)
4,076
530
670
(140)

–
44
(44)
(10)
(34)

(182)
3,576
429
(74)
503

63
789
562
288
274

(2,747)
19,424
386
(335)
721

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax
Exploration and production activities –

subsidiaries (as above)

Midstream and other activities –

subsidiariesi

Equity-accounted entitiesj k
Total replacement cost profit (loss)

before interest and tax

1,252

335

(1,528)

(185)

(965)

530

(44)

429

562

386

(417)
–

54
(1)

(14)
20

(137)
–

187
447

(142)
(12)

(2)
597

(81)
266

13
–

(539)
1,317

835

388

(1,522)

(322)

(331)

376

551

614

575

1,164

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. Amounts relating to the management and ownership of crude oil and natural gas pipelines,
LNG liquefaction and transportation operations 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 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 Rest of Asia amounts include BP’s participating interest in the Abu Dhabi ADCO concession.
d Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as

incurred.

e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $32 million. The UK region includes a $454-million gain which is offset by corresponding

charges primarily in the US region, relating to the group self-insurance programme.

g Excludes the unwinding of the discount on provisions and payables amounting to $152 million which is included in finance costs in the group income statement.
h UK region includes the deferred tax impact of the enactment of legislation to reduce the UK supplementary charge tax rate applicable to profits arising in the North Sea from 20% to 10%.
i Midstream and other activities excludes inventory holding gains and losses.
j The profits of equity-accounted entities are included after interest and tax.
k Includes the results of BP’s 30% interest in Aker BP ASA from 1 October 2016.

188

BP Annual Report and Form 20-F 2016

Oil and natural gas exploration and production activities – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russiaa

Rest of
Asia

Equity-accounted entities (BP share)
Capitalized costs at 31 Decemberb c

Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation

Net capitalized costs

–
–

–

2,702
296

2,998
48

2,950

Costs incurred for the year ended 31 Decemberb d e

Acquisition of propertiesc

Proved
Unproved

Exploration and appraisal costsd
Development

Total costs

–
–

–
–
–

–

–
–

–
18
54

Results of operations for the year ended 31 Decemberb

Sales and other operating revenuesf

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and

amortization

Net impairments and losses on sale
of businesses and fixed assets

Profit (loss) before taxation
Allocable taxes

Results of operationsg

–
–

–

–
–
–
–

–

–
–

–

162
–

162

13
36
–
(13)

–

78
75

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

10,211
6

10,217
4,615

5,602

–
–

–
7
559

566

1,865
–

1,865

–
559
335
(429)

499

164

1,128

737
319

418

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

19,818
369

20,187
4,379

15,808

1,956
70

2,026
105
2,014

4,145

–
8,129

8,129

50
1,106
3,391
368

1,072

6,012

2,117
433

1,684

3,009
26

3,035
3,035

–

–
–

–
1
371

372

876
16

892

–
145
352
3

386

–

886

6
3

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities

Exploration and production activities –
equity-accounted entities after tax
(as above)

Midstream and other activities

after taxh

Total replacement cost profit (loss)

after interest and tax

–

(4)

(1)

–

418

–

1,684

(12)

(1,087)

263

447

(12)

597

266

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

$ million

2016

Total

35,740
697

36,437
12,077

24,360

1,956
70

2,026
131
2,998

5,155

2,903
8,145

11,048

63
1,846
4,078
(71)

2,005

189

8,110

2,938
830

2,108

(791)

1,317

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. Amounts relating to the management and ownership of crude

oil and natural gas pipelines, LNG liquefaction and transportation operations 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 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.
f Presented net of transportation costs and sales taxes.
g Includes the results of BP’s 30% interest in Aker BP ASA from 1 October 2016.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.

BP Annual Report and Form 20-F 2016

189

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Oil and natural gas exploration and production activities – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2015

Total

Subsidiaries
Capitalized costs at 31 Decembera b

Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation

Net capitalized costs

33,214
437

33,651
21,447

12,204

10,568
168

10,736
7,172

80,716
5,602

86,318
43,290

3,564

43,028

3,559
2,377

5,936
191

5,745

11,051
2,964

14,015
6,251

42,807
4,635

47,442
29,406

7,764

18,036

–
–

–

–
–

–
5
–

–
–

–

5
–
–
27

28,474
2,740

31,214
15,967

15,247

5,177
933

6,110
2,677

215,566
19,856

235,422
126,401

3,433

109,021

–
–

–
102
3,439

3,541

800
4,028

4,828

53
1,083
834
76

–
–

–
125
128

253

407
(54)

353
1,794
13,458

15,605

1,450
340

1,790

52
166
46
215

7,043
17,702

24,745

2,353
7,519
1,036
2,621

Costs incurred for the year ended 31 Decembera b

Acquisition of properties

Proved
Unproved

Exploration and appraisal costsc
Development

Total costs

17
–

17
178
1,784

1,979

–
–

–
11
73

Results of operations for the year ended 31 Decembera

131
56

187
651
3,662

4,500

651
7,427

8,078

960
2,777
215
2,460

–
–

–
75
324

399

14
2

108
77
–
48

–
(118)

(118)
114
1,299

1,295

259
8

267
533
2,749

3,549

1,594
33

1,627

51
703
214
140

1,829
4,005

5,834

1,001
1,521
–
358

496
1,149

1,645

115
879
(273)
(795)

209
718

927

8
313
–
92

Sales and other operating revenuesd

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)e
Depreciation, depletion and

amortization

Net impairments and (gains) losses

on sale of businesses and
fixed assets

Profit (loss) before taxationf
Allocable taxesg

Results of operations

949

544

3,671

673

3,412

–

2,420

322

12,004

(390)

485

1,160
(930)

2,090

340

974

10,423

(47)
159

(2,345)
(857)

(206)

(1,488)

–

246

(230)
(5)

(225)

101

846

1,882

7,138

(255)
(28)

(227)

(1,304)
694

(1,998)

–

(32)
(5)

(27)

105

4,571

257
(66)

323

140

941

849
472

377

1,159

26,692

(1,947)
(566)

(1,381)

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax

Exploration and production activities –

subsidiaries (as above)

Midstream and other activities –

subsidiariesh

Equity-accounted entitiesi

Total replacement cost profit (loss)

1,160

(47)

(2,345)

(230)

(255)

(1,304)

(32)

257

849

(1,947)

401
–

110
(7)

43
19

10
–

211
370

(39)
(552)

(16)
1,326

67
363

14
–

801
1,519

before interest and tax

1,561

(2,283)

(220)

326

(1,895)

1,278

687

863

373

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 $120 million. The UK region includes a $832-million gain which is offset by corresponding

charges primarily in the US region, relating to the group self-insurance programme.

f Excludes the unwinding of the discount on provisions and payables amounting to $164 million which is included in finance costs in the group income statement.
g UK region includes the one-off deferred tax impact of the enactment of legislation to reduce the UK supplementary charge tax rate applicable to profits arising in the North Sea from 32% to

20%.

h Midstream and other activities excludes inventory holding gains and losses.
i BP’s share of the profits of equity-accounted entities are included after interest and tax reported by those entities.

190

BP Annual Report and Form 20-F 2016

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)
Capitalized costs at 31 Decemberb c

Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation

Net capitalized costs

–
–

–

Costs incurred for the year ended 31 Decemberb d e

Acquisition of propertiesc

Proved
Unproved

Exploration and appraisal costsd
Development

Total costs

–
–

–
–
–

–

Results of operations for the year ended 31 Decemberb

Sales and other operating revenuesf

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and

amortization

Net impairments and losses on sale
of businesses and fixed assets

Profit (loss) before taxation
Allocable taxes

Results of operations

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

9,824
–

9,824
4,117

5,707

–
–

–
8
1,128

1,136

2,060
–

2,060

3
647
425
(381)

465

1,239

821
504

317

Russiaa

Rest of
Asia

12,728
437

13,165
2,788

10,377

3,486
26

3,512
3,458

16
26

42
123
1,702

1,867

–
8,592

8,592

52
1,083
3,911
284

992

–

6,322

2,270
449

1,821

–
–

–
1
443

444

1,022
19

1,041

–
168
388
–

484

1,075

(34)
1

(35)

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities

Exploration and production activities –
equity – accounted entities after tax
(as above)

Midstream and other activities after

taxg

Total replacement cost profit (loss)

after interest and tax

–

(7)

–

317

–

1,821

(35)

(552)

(495)

398

370

(552)

1,326

363

$ million

2015

Total

26,038
463

26,501
10,363

16,138

16
26

42
132
3,273

3,447

3,082
8,611

11,693

55
1,898
4,724
(97)

1,941

115

8,636

3,057
954

2,103

(584)

1,519

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

incurred.

e 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.
f Presented net of transportation costs and sales taxes.
g Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.

BP Annual Report and Form 20-F 2016

191

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Oil and natural gas exploration and production activities – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2014

Total

Subsidiaries
Capitalized costs at 31 Decembera b

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 Decembera b

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 Decembera d

Sales and other operating revenuese

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)f
Depreciation, depletion and

amortization

Net impairments and (gains) losses
on sale of businesses and fixed
assets

Profit (loss) before taxationg
Allocable taxes

Results of operations

529
1,069

1,598

94
979
(234)
(1,515)

77
1,662

1,218
14,894

1,739

16,112

47
436
–
77

1,294
3,492
690
3,260

506

676

3,805

2,537

2,367

2,278

(28)

3,514

12,513

(769)
(1,383)

(1,775)
(1,108)

614

(667)

3,599
1,269

2,330

–
–

–
109
706

815

4
15

63
34
–
55

–

156

(137)
15

(152)

–
75

75
325
983

1,383

2,802
450

3,252

502
783
175
284

–
57

57
899
2,881

3,837

2,536
6,289

8,825

860
1,542
–
120

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
57

24,177
2,773

26,950
13,501

13,449

5,061
888

5,949
2,215

199,809
21,722

221,531
113,554

3,734

107,977

557
–

557
194
3,205

3,956

1,135
6,951

8,086

712
1,289
2,234
(69)

–
–

–
201
169

370

605
478

1,083
2,911
15,096

19,090

2,574
624

3,198

60
232
93
343

10,875
31,954

42,829

3,632
8,787
2,958
2,612

678

3,343

–

2,461

255

11,728

2,433

819
865

(46)

1,128

6,993

1,832
1,216

616

–

(57)
3

(60)

391

7,018

1,068
67

1,001

–

6,317

983

36,034

2,215
1,161

1,054

6,795
2,105

4,690

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax

Exploration and production activities –

subsidiaries (as above)

Midstream and other activities –

subsidiariesh

Equity-accounted entitiesi

Total replacement cost profit (loss)

before interest and tax

(769)

(1,775)

3,599

(137)

819

1,832

(57)

1,068

2,215

6,795

163
–

99
62

703
23

130
–

175
480

(170)
(33)

(26)
2,125

(63)
557

14
–

1,025
3,214

(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. Amounts relating to the management and ownership of crude oil and natural gas pipelines,
LNG liquefaction and transportation operations 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.

incurred.

d Amendments have been made to previously published amounts for the Australasia region with no overall effect on total replacement cost before interest and tax.
e Presented net of transportation costs, purchases and sales taxes.
f Includes property taxes, other government take and the fair value gain on embedded derivatives of $430 million. The UK region includes a $1,016-million gain which is offset by corresponding

charges primarily in the US region, relating to the group self-insurance programme.

g 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.
h Midstream and other activities excludes inventory holding gains and losses.
i BP’s share of the profits of equity-accounted entities are included after interest and tax reported by those entities.

192

BP Annual Report and Form 20-F 2016

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)
Capitalized costs at 31 Decemberb c

Gross capitalized costs
Proved properties
Unproved properties

Accumulated depreciation

Net capitalized costs

–
–

–

Costs incurred for the year ended 31 Decemberb c

Acquisition of propertiesd

Proved
Unproved

Exploration and appraisal costse
Developmentf

Total costs

–
–

–
–
–

–

Results of operations for the year ended 31 Decemberb

Sales and other operating revenuesg

Third parties
Sales between businesses

Exploration expenditure
Production costs
Production taxes
Other costs (income)
Depreciation, depletion and

amortization

Net impairments and losses on sale
of businesses and fixed assets

Profit (loss) before taxation
Allocable taxes

Results of operations

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

8,719
5

8,724
3,652

5,072

–
–

–
5
1,026

1,031

2,472
–

2,472

4
567
721
4

370

1,691

781
402

379

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
326

330

–
10,972

10,972

1,257
19

1,276

62
1,318
5,214
302

1,509

–

8,405

2,567
637

1,930

1
152
692
–

371

–

1,216

60
29

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

Upstream and Rosneft segments replacement cost profit (loss) before interest and tax from equity-accounted entities

Exploration and production activities –
equity-accounted entities after tax
(as above)

Midstream and other activities after

taxh

Total replacement cost profit (loss)

after interest and tax

–

379

101

–

1,930

(33)

195

526

480

(33)

2,125

557

$ million

2014

Total

24,763
406

25,169
8,669

16,500

(46)
87

41
137
3,265

3,443

3,729
10,991

14,720

67
2,037
6,627
306

2,250

11,312

3,408
1,068

2,340

874

3,214

–
–

–

–
–

–
–
–

–

–
–

–

–
–
–
–

–

–
–

–

c 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.
d Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
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 An amendment has been made to the amount previously disclosed for the Rest of Asia region.
g Presented net of transportation costs and sales taxes.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.

BP Annual Report and Form 20-F 2016

193

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Movements in estimated net proved reserves

Crude oila b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimatesd
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place

At 31 Decemberf
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
Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

million barrels

2016

Total

141
298

440

13
–
3
2
(29)
–

(11)

155
274

429

–
–

–

–
–
–
–
–
–

–

–
–

–

Rest of
Europe

USc

890
577

86
19

106

1,467

–
–
–
–
(9)
(97)

(106)

(30)
1
3
–
(119)
(1)

(145)

Rest of
North
America

46
205

252

–
–
–
4
(5)
–

(1)

826
497

1,322

42
209

251

–
–

–

–
–

–

–
–
116
–
(3)
–

114

45
69

114

–
–

–

–
–
–
–
–
–

–

–
–

–

890
577

–
–

–

–
–
–
–
–
–

–

–
–

–

47
205

252

42
209

251

Russia

Rest of
Asia

340
89

429

22
3
–
–
(96)
–

(71)

317
42

358

2
–

–
–
–
–
–
–

–

1
–

342
89

431

318
42

360

–
–

–

–
–
–
–
–
–

–

–
–

–

2,844
1,981

4,825

33
4
456
285
(305)
(2)

471

3,162
2,134

5,296

2,844
1,981

4,825

3,162
2,134

5,296

598
192

790

543
70
25
–
(75)
(1)

562

1,107
245

1,352

68
–

13
–
–
–
(37)
(1)

(25)

43
1

666
192

858

1,150
246

1,395

8
18

(2)
–
–
–
(4)
–

(6)

9
11

311
311

622

(2)
1
36
16
(28)
–

321
325

646

319
329

648

330
336

666

35
16

2
–
1
–
(6)
(2)

(5)

32
14

–
–

–

–
–
–
–
–
–

–

–
–

–

35
16

32
14

2,146
1,414

3,560

548
74
32
6
(341)
(102)

218

2,487
1,291

3,778

3,225
2,292

5,517

45
5
609
301
(373)
(2)

584

3,573
2,529

6,101

5,371
3,707

9,078

6,060
3,819

9,879

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

141
298

86
19

At 31 December
Developed
Undeveloped

440

106

1,467

155
274

429

45
69

826
497

114

1,322

a Crude oil includes condensate and bitumen. 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 component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 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 Rest of Asia includes additions from Abu Dhabi ADCO concession.
e Includes 6 million barrels of crude oil 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 347 million barrels of crude oil in respect of the 6.58% non-controlling interest in Rosneft, including 28 mmbbl held through BP’s equity-accounted interest in Taas-Yuryakh

Neftegazodobycha.

h Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,330 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 62 million barrels in Venezuela

and 5,268 million barrels in Russia.

194

BP Annual Report and Form 20-F 2016

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

2016

Total

Rest of
Europe

11
1

–
–
–
–
(1)
(10)

(12)

–
–

–

–
–

–

–
–
5
–
–
–

3
2

5
4

7
–
1
–
(2)
–

13
3

–
–

–

–
–
–
–
–
–

–

–
–

–

Rest of
North
America

Russia

Rest of
Asia

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

7
28

–
–
–
–
(2)
–

(2)

5
28

–
–

–

–
–
–
–
–
–

–

–
–

–

7
28

5
28

5
10

1
–
–
–
(2)
–

(1)

13
1

13
–

(2)
–
–
–
–
–

(2)

11
–

18
10

24
1

–
–

–

–
–
–
–
–
–

–

–
–

–

32
15

18
–
–
–
–
–

50
15

32
15

50
15

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

269
70

339

(24)
3
4
–
(24)
–

(40)

226
73

299

–
–

–

–
–
–
–
–
–

–

–
–

–

269
70

339

226
73

299

9
2

–
–
–
–
(1)
–

(1)

9
2

–
–

–

–
–
–
–
–
–

–

–
–

–

9
2

308
115

422

(14)
3
6
–
(34)
(10)

(49)

266
107

373

45
15

16
–
5
–
–
–

65
17

352
130

482

331
123

454

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

5
4

11
1

At 31 December
Developed
Undeveloped

13
3

3
2

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
d Includes 10 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 65 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 65 million barrels in

Russia.

BP Annual Report and Form 20-F 2016

195

Movements in estimated net proved reserves – continued

Total liquidsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimatesd
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place

At 31 Decemberf
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

Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

USc

Russia

Rest of
Asia

million barrels

2016

Total

147
303

449

20
–
5
2
(31)
–

(4)

168
277

445

–
–

–

–
–
–
–
–
–

–

–
–

–

98
20

117

1,159
647

1,806

46
205

252

–
–
–
–
(10)
(108)

(117)

(54)
5
7
–
(143)
(1)

(185)

–
–
–
4
(5)
–

(1)

–
–

–

–
–

–

–
–
122
–
(3)
–

119

48
71

119

1,051
569

1,621

42
209

251

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

1,159
647

1,806

1,051
569

1,621

47
205

252

42
209

251

15
46

(2)
–
–
–
(6)
–

(8)

14
39

311
312

622

(2)
1
36
16
(28)
–

321
325

646

326
357

684

335
364

699

346
99

444

23
3
–
–
(98)
–

(72)

330
43

372

14
–

(2)
–
–
–
–
–

(2)

12
–

360
99

459

342
43

385

–
–

–

–
–
–
–
–
–

–

–
–

–

2,876
1,996

4,872

51
4
456
285
(305)
(2)

489

3,213
2,148

5,361

2,876
1,996

4,872

3,213
2,148

5,361

598
192

790

543
70
25
–
(75)
(1)

562

1,107
245

1,352

68
–

13
–
–
–
(37)
(1)

(25)

43
1

666
192

858

1,150
246

1,395

45
18

3
–
1
–
(7)
(2)

(5)

42
16

–
–

–

–
–
–
–
–
–

–

–
–

–

45
18

42
16

2,453
1,529

3,982

533
78
38
6
(375)
(112)

168

2,753
1,398

4,151

3,270
2,307

5,577

61
5
614
301
(374)
(2)

605

3,637
2,545

6,183

5,723
3,836

9,560

6,390
3,943

10,333

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

147
302

98
20

At 31 December
Developed
Undeveloped

449

117

168
277

445

48
71

119

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 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 Rest of Asia includes additions from Abu Dhabi ADCO concession.
e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
f Also includes 16 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 347 million barrels in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha.
i Total proved liquid reserves held as part of our equity interest in Rosneft is 5,395 million barrels, comprising less than 1 million barrels in Canada, 62 million barrels in Venezuela, less than

1 million barrels in Vietnam and 5,333 million barrels in Russia.

196

BP Annual Report and Form 20-F 2016

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
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

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

2016

Total

billion cubic feet

2,071
5,989

8,060

847
2,305

3,152

(1,042)
42
–
355
(624)
(37)

(1,306)

(19)
1
–
43
(219)
–

(194)

1,784
4,970

6,755

767
2,191

2,958

–
–

–

–
–
–
–
–
–

–

–
–

–

1,463
598

2,061

386
–

386

4,962
6,176

11,139

62
1
19
128
(190)
–

34
–
–
–
(8)
–

736
10
81
343
(461)
(1)

709

1,546
534

2,080

412
–

412

5,544
6,304

11,847

1,803
3,455

5,257

548
22
–
–
(152)
(17)

401

1,890
3,769

5,659

44
4

5
–
–
–
(15)
(8)

(18)

26
4

274
14

288

6,257
2,105

8,363

348
343

691

133
–
95
–
(71)
–

158

499
350

848

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–
–
–
(33)
(256)

(288)

–
–

–

–
–

–

–
–
115
–
(4)
–

110

89
21

110

(231)
469
91
1
(676)
(2)

(348)

5,447
2,567

8,014

–
–

–

–
–
–
–
–
–

–

–
–

–

6,257
2,105

8,363

5,447
2,567

8,014

–
–

–

3
–
–
–
(4)
–

–

–
–

–

1
–

–
–
–
–
–
–

–

–
–

1
–

–
–

–

3,408
1,343

4,751

15,009
15,553

30,563

396
–
252
–
(306)
(439)

(211)
534
438
399
(2,085)
(750)

(97)

(1,675)

3,012
1,643

4,654

13,398
15,490

28,888

–
–

–

–
–
–
–
–
–

–

–
–

–

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

6,856
6,778

13,634

836
11
216
471
(680)
(8)

846

7,617
6,863

14,480

21,865
22,331

44,197

21,015
22,353

43,368

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

348
343

274
14

At 31 December
Developed
Undeveloped

691

288

499
350

848

89
21

110

3,534
6,587

1,233
2,305

4,962
6,176

10,121

3,538

11,139

3,330
5,505

8,835

1,179
2,191

5,544
6,304

3,370

11,847

1,847
3,459

5,305

1,916
3,772

5,688

3,408
1,343

4,751

3,012
1,643

4,654

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 176 billion cubic feet of natural gas consumed in operations, 145 billion cubic feet in subsidiaries, 31 billion cubic feet in equity-accounted entities.
d Includes 2,026 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 300 billion cubic feet of natural gas in respect of the 2.53% non-controlling interest in Rosneft including 3 billion cubic feet held through BP’s equity-accounted interest in Taas-Yuryakh

Neftegazodobycha.

g Total proved gas reserves held as part of our equity interest in Rosneft is 11,900 billion cubic feet, comprising 1 billion cubic feet in Canada, 33 billion cubic feet in Venezuela, 23 billion cubic

feet in Vietnam and 11,843 billion cubic feet in Russia.

BP Annual Report and Form 20-F 2016

197

Movements in estimated net proved reserves – continued

million barrels of oil equivalentc

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

USd

Russia

Rest of
Asia

Total hydrocarbonsa b

Subsidiaries
At 1 January
Developed
Undeveloped

Changes attributable to

Revisions of previous estimatese
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productionf g
Sales of reserves-in-place

At 31 Decemberh
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
Productiong
Sales of reserves-in-place

At 31 Decemberj k

Developed
Undeveloped

207
362

568

43
–
21
2
(43)
–

254
338

592

–
–

–

–
–
–
–
–
–

–

–
–

–

145
22

167

2,238
1,010

3,248

46
205

252

373
1,078

1,451

–
–
–
–
(16)
(152)

(167)

(94)
86
23
–
(260)
(1)

(245)

1
–
–
4
(5)
–

(1)

(181)
7
–
61
(114)
(7)

(233)

–
–

–

–
–

–

–
–
142
–
(3)
–

138

63
75

138

1,990
1,012

3,002

42
209

251

321
896

1,217

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

2,238
1,010

3,248

1,990
1,012

3,002

47
205

252

42
209

251

563
415

978

9
1
39
38
(61)
–

588
417

1,005

936
1,493

2,429

909
1,313

2,222

492
496

988

20
3
–
8
(136)
–

(105)

462
420

882

81
–

4
–
–
–
(2)
–

83
–

573
496

1,069

545
420

966

–
–

–

–
–
–
–
–
–

–

–
–

–

3,732
3,061

6,792

178
6
470
344
(385)
(2)

611

4,168
3,235

7,404

3,732
3,061

6,792

4,168
3,235

7,404

909
788

1,696

637
74
25
–
(101)
(4)

631

1,433
895

2,327

76
1

14
–
–
–
(40)
(2)

(28)

47
1

984
788

1,773

1,480
896

2,376

2016

Total

5,041
4,211

9,252

497
170
113
75
(735)
(241)

(121)

5,063
4,068

9,131

4,452
3,476

7,928

205
7
652
382
(491)
(4)

751

4,951
3,729

8,679

632
250

882

71
–
44
–
(60)
(78)

(22)

561
299

860

–
–

–

–
–
–
–
–
–

–

–
–

–

632
250

882

561
299

860

9,493
7,687

17,180

10,014
7,797

17,810

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

207
362

145
22

At 31 December
Developed
Undeveloped

568

167

254
338

592

63
75

138

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
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 9 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 Rest of Asia includes additions from Abu Dhabi ADCO concession.
f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 3 thousand barrels per day for equity-accounted entities.
g Includes 30 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted

entities.

h Includes 366 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
j Includes 402 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 29 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh

Neftegazodobycha.

k Total proved reserves held as part of our equity interest in Rosneft is 7,447 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 68 million barrels of

oil equivalent in Venezuela, 4 million barrels of oil equivalent in Vietnam and 7,375 million barrels of oil equivalent in Russia.

198

BP Annual Report and Form 20-F 2016

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
Productione
Sales of reserves-in-place

At 31 Decemberf
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
Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asiad

million barrels

2015

Total

159
329

488

(23)
–
1
–
(27)
(1)

(48)

141
298

440

–
–

–

–
–
–
–
–
–

–

–
–

–

95
22

117

1,030
664

1,694

9
163

172

2
–
–
–
(14)
–

(12)

86
19

(130)
15
–
3
(115)
–

(227)

890
577

106

1,467

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

1,030
664

1,694

39
–
–
42
(1)
–

46
205

252

–
–

–
–
–
–
–
–

–

–
–

–

9
164

173

47
205

252

10
22

(2)
–
–
–
(5)
–

(6)

8
18

316
314

630

9
3
–
9
(28)
–

(8)

311
311

622

326
336

662

319
329

648

317
120

437

80
2
6
2
(98)
–

(8)

340
89

429

2
–

–
–
–
–
–
–

–

2
–

319
120

439

342
89

431

–
–

–

–
–
–
–
–
–

–

–
–

–

2,997
1,933

4,930

(23)
–
28
185
(295)
(1)

(105)

2,844
1,981

4,825

2,997
1,933

4,930

2,844
1,981

4,825

384
197

581

295
–
–
–
(87)
–

208

598
192

790

89
11

101

3
–
–
–
(35)
–

(32)

68
–

473
208

682

666
192

858

40
19

(2)
–
–
–
(6)
–

(8)

35
16

–
–

–

–
–
–
–
–
–

–

–
–

–

40
19

35
16

2,044
1,538

3,582

260
18
7
47
(353)
(1)

(21)

2,146
1,414

3,560

3,405
2,258

5,663

(11)
3
28
194
(358)
(1)

(146)

3,225
2,292

5,517

5,448
3,796

9,244

5,371
3,707

9,078

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

159
329

95
22

488

117

At 31 December
Developed
Undeveloped

141
298

440

86
19

890
577

106

1,467

a Crude oil includes condensate and bitumen. 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 component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 23 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 Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There was no impact on 2015 proved reserves totals.
e Includes 8 million barrels of crude oil 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 70 million barrels of crude oil in respect of the 1.27% non-controlling interest in Rosneft, including 28 mmbbl held through BP’s equity accounted interest in Taas-Yuryakh

Neftegazodobycha.

h Total proved crude oil reserves held as part of our equity interest in Rosneft is 4,823 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 26 million barrels in Venezuela

and 4,797 million barrels in Russia.

BP Annual Report and Form 20-F 2016

199

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

2015

Total

Rest of
Europe

6
3

2
–
–
–
(2)
–

–

5
4

–
–

–

–
–
–
–
–
–

–

–
–

–

13
1

–
–
–
–
(2)
–

(2)

11
1

–
–

–

–
–
–
–
–
–

–

–
–

–

Rest of
North
America

Russia

Rest of
Asia

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

11
28

–
–
–
–
(4)
–

(4)

7
28

–
–

–

–
–
–
–
–
–

–

–
–

–

11
28

7
28

5
7

6
–
–
–
(3)
–

5
10

15
–

(3)
–
–
–
–
–

(3)

13
–

20
7

18
10

–
–

–

–
–
–
–
–
–

–

–
–

–

30
16

1
–
–
–
–
–

32
15

30
16

32
15

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–

–

323
104

427

(80)
12
3
–
(23)
(1)

(88)

269
70

339

–
–

–

–
–
–
–
–
–

–

–
–

–

323
104

427

269
70

339

6
3

3
–
–
–
(1)
–

9
2

–
–

–

–
–
–
–
–
–

–

–
–

–

6
3

9
2

364
146

510

(69)
12
4
–
(34)
(1)

(88)

308
115

422

46
16

(2)
–
–
–
–
–

(2)

45
15

410
163

572

352
130

482

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

6
3

13
1

At 31 December
Developed
Undeveloped

5
4

11
1

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 4 thousand barrels per day for equity-accounted entities.
d Includes 11 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 47 million barrels in

Russia.

200

BP Annual Report and Form 20-F 2016

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
Productione
Sales of reserves-in-place

At 31 Decemberf
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

Developed
Undeveloped

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asiad

million barrels

2015

Total

166
332

497

(20)
–
1
–
(29)
(1)

(48)

147
302

449

–
–

–

–
–
–
–
–
–

–

–
–

–

108
23

131

1,352
769

2,121

9
163

172

2
–
–
–
(16)
–

(14)

(210)
28
3
4
(138)
(1)

(315)

39
–
–
42
(1)
–

98
20

117

1,159
647

1,806

46
205

252

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–
–
–
–
–
–

(1)

–
–

–

1,352
769

2,121

1,159
647

1,806

9
164

173

47
205

252

21
50

(2)
–
–
–
(8)
–

(10)

15
46

316
314

630

9
3
–
9
(28)
–

(8)

311
312

622

337
364

701

326
357

684

322
127

449

86
2
6
2
(101)
–

(5)

346
99

444

17
–

(3)
–
–
–
–
–

(3)

14
–

339
127

466

360
99

459

–
–

–

–
–
–
–
–
–

–

–
–

–

3,028
1,949

4,976

(22)
–
28
185
(295)
(1)

(104)

2,876
1,996

4,872

3,028
1,949

4,976

2,876
1,996

4,872

384
197

581

295
–
–
–
(87)
–

208

598
192

790

89
11

101

3
–
–
–
(35)
–

(32)

68
–

473
208

682

666
192

858

46
22

1
–
–
–
(7)
–

(6)

45
18

–
–

–

–
–
–
–
–
–

–

–
–

–

46
22

45
18

2,407
1,684

4,092

191
30
11
48
(387)
(2)

(109)

2,453
1,529

3,982

3,451
2,274

5,725

(13)
3
28
194
(358)
(1)

(147)

3,270
2,307

5,577

5,858
3,958

9,817

5,723
3,836

9,560

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

166
332

108
23

At 31 December
Developed
Undeveloped

497

131

147
302

449

98
20

117

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Proved reserves in the Prudhoe Bay field in Alaska include an estimated 23 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 Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There was no impact on 2015 proved reserves totals.

e Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 4 thousand barrels per day for equity-accounted entities.
f Also includes 19 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 70 million barrels in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity accounted interest in Taas-Yuryakh Neftegazodobycha.
i Total proved liquid reserves held as part of our equity interest in Rosneft is 4,871 million barrels, comprising less than 1 million barrels in Canada, 26 million barrels in Venezuela, less than

1 million barrels in Vietnam and 4,844 million barrels in Russia.

BP Annual Report and Form 20-F 2016

201

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

2015

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

2,352
6,313

8,666

901
1,597

2,497

132
–
29
–
(709)
(58)

(605)

203
7
554
174
(248)
(35)

654

2,071
5,989

8,060

847
2,305

3,152

–
–

–

–
–
–
–
–
–

–

–
–

–

1,228
717

1,945

400
–

400

4,674
5,111

9,785

81
8
–
209
(182)
(1)

116

(14)
–
–
–
–
–

(14)

1,604
–
5
175
(430)
–

1,354

1,463
598

2,061

386
–

386

4,962
6,176

11,139

1,688
3,892

5,580

(165)
–
–
–
(157)
–

(322)

1,803
3,455

5,257

60
9

(2)
–
–
–
(19)
–

(21)

44
4

382
386

768

(12)
4
–
–
(65)
(5)

(77)

348
343

691

–
–

–

–
–
–
–
–
–

–

–
–

–

300
19

318

7,168
2,447

9,615

14
–
–
–
(44)
–

(30)

(1,120)
432
65
5
(628)
(6)

(1,252)

274
14

288

6,257
2,105

8,363

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

7,168
2,447

9,615

6,257
2,105

8,363

17
–

(13)
–
–
–
(4)
–

(17)

–
–

–

1
1

(1)
–
–
–
–
–

(1)

1
–

18
1

1
–

3,316
1,719

5,035

16,124
16,372

32,496

13
–
–
–
(297)
–

(284)

(948)
443
648
179
(2,151)
(104)

(1,933)

3,408
1,343

4,751

15,009
15,553

30,563

–
–

–

–
–
–
–
–
–

–

–
–

–

6,363
5,837

12,200

1,669
8
5
384
(632)
(1)

1,434

6,856
6,778

13,634

22,487
22,209

44,695

21,865
22,331

44,197

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

382
386

300
19

At 31 December
Developed
Undeveloped

768

318

348
343

691

274
14

288

3,581
7,030

10,610

1,301
1,597

2,897

4,674
5,111

9,785

3,534
6,587

1,233
2,305

4,962
6,176

10,121

3,538

11,139

1,748
3,901

5,648

1,847
3,459

5,305

3,316
1,719

5,035

3,408
1,343

4,751

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes 175 billion cubic feet of natural gas consumed in operations, 146 billion cubic feet in subsidiaries, 29 billion cubic feet in equity-accounted entities.
d Includes 2,359 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 129 billion cubic feet of natural gas in respect of the 0.23% non-controlling interest in Rosneft including 5 billion cubic feet held through BP’s equity accounted interest in Taas-Yuryakh

Neftegazodobycha.

g Total proved gas reserves held as part of our equity interest in Rosneft is 11,169 billion cubic feet, comprising 1 billion cubic feet in Canada, 13 billion cubic feet in Venezuela, 22 billion cubic

feet in Vietnam and 11,133 billion cubic feet in Russia.

202

BP Annual Report and Form 20-F 2016

Movements in estimated net proved reserves – continued

million barrels of oil equivalentc

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USd

Rest of
North
America

Russia

Rest of
Asiae

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
Productionf g
Sales of reserves-in-place

At 31 Decemberh
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
Productiong
Sales of reserves-in-place

At 31 Decemberj k

Developed
Undeveloped

232
398

630

(22)
1
1
–
(40)
(1)

(62)

207
362

568

–
–

–

–
–
–
–
–
–

–

–
–

–

160
26

186

2,588
1,191

3,779

12
163

175

426
1,139

1,565

4
–
–
–
(23)
–

(19)

(403)
102
15
4
(247)
(2)

(531)

36
–
–
42
(2)
–

21
–
5
–
(130)
(10)

(114)

145
22

167

2,238
1,010

3,248

46
205

252

373
1,078

1,451

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
1

(1)
–
–
–
–
–

(1)

–
–

–

528
438

965

23
5
–
45
(60)
–

563
415

978

477
403

880

121
3
102
32
(144)
(6)

108

492
496

988

86
–

(5)
–
–
–
–
–

(5)

81
–

2015

Total

5,187
4,507

9,695

27
106
122
79
(758)
(19)

(443)

5,041
4,211

9,252

4,548
3,280

7,828

274
5
29
260
(467)
(1)

100

4,452
3,476

7,928

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

618
319

937

4
–
–
–
(58)
–

(55)

632
250

882

–
–

–

–
–
–
–
–
–

–

–
–

–

618
319

937

632
250

882

9,735
7,788

17,523

9,493
7,687

17,180

–
–

–

–
–
–
–
–
–

–

–
–

–

3,834
2,830

6,663

255
–
29
215
(369)
(1)

129

3,732
3,061

6,792

3,834
2,830

6,663

3,732
3,061

6,792

675
868

1,543

267
–
–
–
(114)
–

153

909
788

1,696

100
13

112

3
–
–
–
(39)
–

(36)

76
1

775
881

1,656

984
788

1,773

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

232
398

160
26

At 31 December
Developed
Undeveloped

630

186

207
362

568

145
22

167

2,588
1,191

3,779

2,238
1,010

3,248

12
164

176

47
205

252

954
1,576

2,530

936
1,493

2,429

563
403

966

573
496

1,069

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
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 23 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 Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There was no impact on 2015 proved reserves totals.

f Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 4 thousand barrels per day for equity-accounted entities.
g Includes 30 million barrels of oil equivalent of natural gas consumed in operations, 25 million barrels of oil equivalent in subsidiaries, 5 million barrels of oil equivalent in equity-accounted

entities.

h Includes 425 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
j Includes 70 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 28 mmboe held through BP’s equity accounted interest in Taas-Yuryakh

Neftegazodobycha.

k Total proved reserves held as part of our equity interest in Rosneft is 6,796 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 28 million barrels of

oil equivalent in Venezuela, 4 million barrels of oil equivalent in Vietnam and 6,764 million barrels of oil equivalent in Russia.

BP Annual Report and Form 20-F 2016

203

Movements in estimated net proved reserves – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asiad

million barrels

2014

Total

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
Productione
Sales of reserves-in-place

At 31 Decemberf
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
Developed
Undeveloped

160
374

534

(41)
2
5
5
(17)
–

(46)

159
329

488

–
–

–

–
–
–
–
–
–

–

–
–

–

147
53

200

1,007
752

1,760

(68)
–
–
–
(15)
–

(82)

87
16
–
–
(123)
(45)

(66)

95
22

117

1,030
664

1,694

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
188

188

(16)
–
–
–
–
–

(16)

9
163

172

–
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
1,785

3,798

85
23
17
13
(305)
(50)

(217)

2,044
1,538

3,581

3,407
2,182

5,590

224
12
–
197
(359)
–

3,405
2,258

5,663

5,421
3,965

9,388

5,448
3,796

9,244

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

160
374

147
53

At 31 December
Developed
Undeveloped

534

200

159
329

488

95
22

117

1,007
752

1,760

1,030
664

1,694

–
189

189

9
164

173

a Crude oil includes condensate and bitumen. 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 component parts.
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 Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There was no impact on 2014 proved reserves totals.

e Includes 10 million barrels of crude oil 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 of crude oil in respect of the 0.15% non-controlling interest in Rosneft.
h 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.

204

BP Annual Report and Form 20-F 2016

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

Rest of
Europe

16
2

(2)
–
–
–
(2)
–

(4)

13
1

–
–

–

–
–
–
–
–
–

–

–
–

–

9
6

(6)
–
–
–
(1)
–

(6)

6
3

–
–

–

–
–
–
–
–
–

–

–
–

–

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

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

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

9
6

16
2

At 31 December
Developed
Undeveloped

6
3

13
1

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
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 2016

205

Movements in estimated net proved reserves – continued

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

USc

Rest of
North
America

Russia

Rest of
Asiad

million barrels

2014

Total

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
Productione
Sales of reserves-in-place

At 31 Decemberf
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

Developed
Undeveloped

169
380

549

(47)
2
5
5
(17)
–

(52)

166
332

497

–
–

–

–
–
–
–
–
–

–

–
–

–

163
55

217

1,297
907

2,204

(70)
–
–
–
(17)
–

(86)

101
28
–
–
(150)
(63)

(83)

108
23

131

1,352
769

2,121

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

–
188

188

(16)
–
–
–
–
–

(16)

9
163

172

–
1

–
–
–
–
–
–

–

–
–

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

57
22

(2)
–
–
–
(8)
–

(10)

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

57
22

46
22

5,865
4,204

10,069

5,858
3,958

9,817

Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped

169
380

163
55

At 31 December
Developed
Undeveloped

549

217

166
332

497

108
23

131

1,297
907

2,204

1,352
769

2,121

–
188

189

9
164

173

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
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 Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There was no impact on 2014 proved reserves totals.

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 Also includes 21 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
g Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
h Includes 38 million barrels in respect of the non-controlling interest in Rosneft.
i 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.

206

BP Annual Report and Form 20-F 2016

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

7,122
2,825

9,947

(46)
–
–
–
(40)
–

(85)

(29)
582
5
2
(625)
(266)

(332)

300
19

318

7,168
2,447

9,615

–
–

–

–
–
–
–
–
–

–

–
–

–

–
–

–

–
–
–
–
–
–

–

–
–

–

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

–
–

–

–
–
–
–
–
–

–

–
–

–

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

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

364
39

At 31 December
Developed
Undeveloped

957

403

382
386

768

300
19

318

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

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
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.

BP Annual Report and Form 20-F 2016

207

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
Asiae

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
Productionf g
Sales of reserves-in-place

At 31 Decemberh
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
Productiong
Sales of reserves-in-place

At 31 Decemberj k

Developed
Undeveloped

280
434

714

(91)
3
6
21
(23)
–

(84)

232
398

630

–
–

–

–
–
–
–
–
–

–

–
–

–

225
62

287

2,525
1,394

3,919

(78)
–
–
–
(24)
–

(101)

96
129
1
1
(258)
(109)

(140)

160
26

186

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

735
324

5,399
4,844

1,059

10,243

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

(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

225
62

At 31 December
Developed
Undeveloped

714

287

232
398

630

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

a Proved reserves exclude royalties due to others, whether payable in cash or in kind, where the royalty owner has a direct interest in the underlying production and the option and ability to make

lifting and sales arrangements independently.

b Because of rounding, some totals may not exactly agree with the sum of their component parts.
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 Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There was no impact on 2014 proved reserves totals.

f 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.
g 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.

h Includes 456 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
i Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
j Includes 54 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft.
k 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

208

BP Annual Report and Form 20-F 2016

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

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

$ million

2016

Total

At 31 December
Subsidiaries
Future cash inflowsa
Future production costb
Future development costb
Future taxationc
Future net cash flows
10% annual discountd e
Standardized measure of

discounted future net cash
flowse f

Equity-accounted entities (BP share)g
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
flowsh i

21,600
13,900
3,000
1,700
3,000
900

2,100

–
–
–
–
–
–

–

–
–
–
–
–
–

–

5,400
3,000
700
1,300
400
200

200

Total subsidiaries and equity-accounted entities
Standardized measure of

72,400
43,100
14,300
500
14,500
4,900

4,500
3,500
1,100
–
(100)
–

11,700
6,600
3,700
100
1,300
200

23,600
10,000
5,100
2,000
6,500
2,800

9,600

(100)

1,100

3,700

–
–
–
–
–
–

–

78,100
42,600
15,400
17,800
2,300
(600)

24,000
9,400
3,500
3,400
7,700
4,100

235,900
129,100
46,100
25,500
35,200
12,300

2,900

3,600

22,900

–
–
–
–
–
–

–

–
–
–
–
–
–

–

34,400
16,500
3,800
3,600
10,500
6,100

4,400

–
–
–
–
–
–

–

159,900
84,300
13,200
10,100
52,300
30,700

1,900
1,200
700
–
–
–

21,600

–

–
–
–
–
–
–

–

201,600
105,000
18,400
15,000
63,200
37,000

26,200

discounted future net cash
flows

2,100

200

9,600

(100)

5,500

3,700

21,600

2,900

3,600

49,100

The following are the principal sources of change in the standardized measure of discounted future net cash flows:

Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yearj

Subsidiaries
(15,200)
13,100
700
(25,500)
12,200
(2,500)
4,900
1,800
3,000
(7,500)

Equity-accounted
entities (BP share)
(5,400)
3,500
900
(5,900)
1,200
900
(2,500)
2,900
2,800
(1,600)

$ million

Total subsidiaries and
equity-accounted
entities
(20,600)
16,600
1,600
(31,400)
13,400
(1,600)
2,400
4,700
5,800
(9,100)

a The marker prices used were Brent $42.82/bbl, Henry Hub $2.46/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 with reference to 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 In certain situations, revenues and costs are included in the standardized measure of discounted future net cash flows valuation and excluded from the determination of proved reserves and
vice versa. This can result in the standardized measure of discounted future net cash flows being negative. Depending on the timing of those cash flows the effect of discounting may be to
increase the discounted future net cash flows.

f Non-controlling interests in BP Trinidad and Tobago LLC amounted to $300 million.
g 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.

h Non-controlling interests in Rosneft amounted to $1,608 million in Russia.
i No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
j 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’.

BP Annual Report and Form 20-F 2016

209

F
n
a
n
c
a

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

Rest of
Europe

North
America

Rest of
North
America

South
America

Africa

Asia

Australasia

$ million

2015

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

27,500
15,700
4,700
2,900

4,200
1,900

7,800
5,300
700
800

1,000
300

98,100
56,300
18,800
3,100

19,900
7,400

7,200
4,200
1,700
–

1,300
900

20,100
8,600
7,000
1,700

2,800
900

32,800
12,000
8,100
3,300

9,400
4,300

Standardized measure of discounted

future net cash flowse

2,300

700

12,500

400

1,900

5,100

–
–
–
–

–
–

–

65,200
35,900
18,200
3,800

7,300
3,700

32,000
15,200
4,500
4,000

8,300
4,400

290,700
153,200
63,700
19,600

54,200
23,800

3,600

3,900

30,400

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

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

39,900
20,200
5,300
3,900

10,500
6,700

3,800

–
–
–
–

–
–

–

182,300
101,200
11,000
12,400

57,700
33,800

3,700
2,200
1,300
100

100
–

23,900

100

–
–
–
–

–
–

–

225,900
123,600
17,600
16,400

68,300
40,500

27,800

future net cash flows

2,300

700

12,500

400

5,700

5,100

23,900

3,700

3,900

58,200

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

Equity-accounted
entities (BP share)

$ million

Total subsidiaries and
equity-accounted
entities

(7,300)
4,500
700
(24,700)
500
2,300
(100)
300
4,700

(19,100)

(35,200)
19,500
1,300
(125,100)
14,000
40,900
3,100
(400)
12,700

(69,200)

Subsidiaries

(27,900)
15,000
600
(100,400)
13,500
38,600
3,200
(700)
8,000

(50,100)

a The marker prices used were Brent $54.17/bbl, Henry Hub $2.59/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 with reference to 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 $600 million.
f The standardized measure of discounted future net cash flows of equity-accounted entities includes standardized measure of discounted future net cash flows of equity-accounted

investments of those entities.

g Non-controlling interests in Rosneft amounted to $93 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 to US

dollars are included within ‘Net changes in prices and production cost’.

210

BP Annual Report and Form 20-F 2016

Standardized measure of discounted future net cash flows and changes therein relating to proved oil and gas
reserves – continued

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

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

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

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

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

–
–
–
–

–
–

–

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

Total subsidiaries and equity-accounted entities
Standardized measure of

F
n
a
n
c
a

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:

s
t
a
t
e
m
e
n
t
s

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 with reference to 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 to US

dollars are included within ‘Net changes in prices and production cost’.

BP Annual Report and Form 20-F 2016

211

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 2016, 2015 and 2014.

Production for the yeara b

Europe

North
America

South
America

Africa

Asia

Australasia

Total

Subsidiariese

Crude oilf

2016
2015
2014

Natural gas liquids

2016
2015
2014

Natural gasg

2016
2015
2014

Equity-accounted entities (BP share)

Crude oilf

2016
2015
2014

Natural gas liquids

2016
2015
2014

Natural gasg

2016
2015
2014

Rest of
Europe

24
38
41

4
5
5

335
323
347

56
56
63

82
111
102

1,656
1,528
1,519

7
–
–

–
–
–

12
–
–

–
–
–

Rest of
North
America

13
3
–

–
–
–

10
10
10

–
–
–

79
72
46

6
7
2

170
155
71

–
–
–

10
12
13

8
11
12

1,689
1,922
2,147

65
68
65

1
3
3

449
435
402

Russiac

–
–
–

840
809
816

4
4
5

263
270
222

5
7
5

513
589
513

–
–
–

4
3
4

18
–
7

1,279
1,195
1,084

Rest
of
Asiad

204
199
147

–
1
–

363
380
408

102
97
98

–
–
–

15
21
21

thousand barrels per day

16
17
19

943
933
834

thousand barrels per day

3
3
3

82
88
91

million cubic feet per day

820
801
814

5,302
5,495
5,585

thousand barrels per day

–
–
–

1,015
974
979

thousand barrels per day

–
–
–

8
10
12

million cubic feet per day

–
–
–

1,773
1,651
1,515

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 worldwide activities, including insignificant amounts outside Russia.
d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq was simplified in 2016 to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods.
e All of the oil and liquid production from Canada is bitumen.
f Crude oil includes condensate.
g Natural gas production excludes gas consumed in operations.

212

BP Annual Report and Form 20-F 2016

Operational and statistical information – continued

Productive oil and gas wells and acreage
The following tables show the number of gross and net productive oil and natural gas wells and total gross and net developed and undeveloped
oil and natural gas acreage in which the group and its equity-accounted entities had interests as at 31 December 2016. 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

North
America

South
America

Africa

Asia

Australasia

Totalb

Rest of
Europe

Number of productive wells at 31 December 2016

Oil wellsc

Gas wellsd

– gross
– net
– gross
– net

126
80
55
23

47
14
1
–

Oil and natural gas acreage at 31 December 2016

Developed

Undevelopede

– gross
– net
– gross
– net

133
76
1,383
978

37
11
1,360
517

Rest of
North
America

150
33
302
149

166
75
12,806
6,353

2,472
849
23,608
10,064

6,462
3,452
5,883
4,318

Russiaa

45,585
9,003
788
156

678
462
160
67

Rest of
Asia

2,002
425
42
11

705
277
31,345
21,801

5,024
941
380,441
74,103

1,536
273
10,018
2,501

4,994
2,736
902
343

1,330
412
20,757
6,404

12
2
66
14

56,066
13,604
25,924
10,827

thousands of acres

173
41
11,617
6,340

15,566
5,558
475,610
123,315

a Based on information received from Rosneft as at 31 December 2016.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes approximately 8,367 gross (1,632 net) multiple completion wells (more than one formation producing into the same well bore).
d Includes approximately 2,825 gross (1,437 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.
e Undeveloped acreage includes leases and concessions.

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

Totala

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

Rest of
North
America

Russia

Rest of
Asia

2016
Exploratory

Productive
Dry

Development
Productive
Dry
2015
Exploratory

Productive
Dry

Development
Productive
Dry
2014
Exploratory

Productive
Dry

Development
Productive
Dry

0.3
1.0

3.4
0.8

–
–

1.6
–

2.9
0.5

3.1
–

Rest of
Europe

0.4
0.3

1.4
–

–
–

0.5
4.7

145.6
–

4.0
–

0.4
–

235.6
–

–
–

5.3
7.9

–
–

0.6
–

99.8
0.6

1.1
0.4

143.1
2.3

3.7
1.4

a Because of rounding, some totals may not exactly agree with the sum of their component parts.

1.8
0.8

294.1
–

1.5
0.1

100.5
3.9

2.1
1.5

20.2
2.0

2.6
1.0

20.7
1.3

0.7
1.6

13.8
1.0

3.4
–

88.5
–

4.5
–

91.4
–

5.3
–

76.2
–

1.6
0.3

55.2
1.0

–
–

51.2
–

0.6
1.4

46.3
0.4

–
–

0.5
–

–
0.2

0.9
–

–
0.2

–
0.4

8.9
7.8

414.6
4.4

12.2
1.6

544.7
3.5

18.5
13.0

537.3
6.6

BP Annual Report and Form 20-F 2016

213

Operational and statistical information – continued

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 2016. Suspended development wells and long-term suspended exploratory wells are also
included in the table.

Europe

North
America

South
America

Africa

Asia

Australasia

Totala

At 31 December 2016
Exploratory
Gross
Net

Development

Gross
Net

1.0
0.9

7.0
2.8

Rest of
Europe

0.1
–

1.0
0.3

7.0
4.1

266.0
113.9

Rest of
North
America

1.0
0.4

14.0
7.0

Russia

Rest of
Asia

2.0
1.6

22.0
14.3

4.0
2.5

39.0
19.1

–
–

2.0
1.3

41.0
13.5

–
–

5.0
0.8

17.1
10.8

395.0
171.7

a Because of rounding, some totals may not exactly agree with the sum of their component parts.

214

BP Annual Report and Form 20-F 2016

Parent company financial statements of BP p.l.c.
Company balance sheet
At 31 December

Non-current assets
Investments
Receivables
Defined benefit pension plan surpluses

Current assets
Receivables
Cash and cash equivalents

Total assets

Current liabilities

Payables

Non-current liabilities

Payables
Deferred tax liabilities
Defined benefit pension plan deficits

Total liabilities

Net assets

Capital and reservesa

Profit and loss account
Brought forward
Profit (loss) for the year
Other movements

Called-up share capital
Share premium account
Other capital and reserves

Note

2016

$ million

2015

2
3
4

5
6
4

166,283
2,951
528

139,241
–
2,516

169,762

141,757

487
50

537

1,062
–

1,062

170,299

142,819

4,225

212

34,432
179
219

34,830

39,055

6,741
877
227

7,845

8,057

131,244

134,762

111,521
(375)
(6,648)

104,498
5,284
12,219
9,243

115,810
571
(4,860)

111,521
5,049
10,234
7,958

131,244

134,762

a See Statement of changes in equity on page 216 for further information.

The financial statements on pages 215-238 were approved and signed by the group chief executive on 6 April 2017 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 215-238 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 2016

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Company statement of changes in equitya

At 1 January 2016

Loss for the year
Other comprehensive income

Total comprehensive income
Dividends
Share-based payments, net of taxb

At 31 December 2016

At 1 January 2015

Profit for the year
Other comprehensive income

Total comprehensive income
Dividends
Share-based payments, net of tax

At 31 December 2015

Capital
redemption
reserve

Merger
reserve

Treasury
shares

Foreign
currency
translation
reserve

Profit and
loss
account

$ million

Total
equity

1,413

26,509

(19,964)

–

111,521

134,762

Share
capital

5,049

–
–

–
137
98

Share
premium
account

10,234

–
–

–
(137)
2,122

–
–

–
–
–

–
–

–
–
–

–
–

–
–
1,521

5,284

12,219

1,413

26,509

(18,443)

5,023

10,260

1,413

26,509

(20,719)

–
–

–
26
–

–
–

–
(26)
–

–
–

–
–
–

–
–

–
–
–

–
–

–
–
755

–
(236)

(236)
–
–

(236)

–
(31)

(31)
–
–

(375)
(1,269)

(1,644)
(4,611)
(768)

(375)
(1,505)

(1,880)
(4,611)
2,973

104,498

131,244

115,810

138,327

571
1,894

2,465
(6,659)
(95)

571
1,863

2,434
(6,659)
660

5,049

10,234

1,413

26,509

(19,964)

–

111,521

134,762

a See Note 8 for further information.
b Share capital and share premium amounts relate to the issue of new ordinary shares to the government of Abu Dhabi. See Notes 3 and 10 for further information. Movements in treasury

shares relate to employee share-based payment plans.

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

216

BP Annual Report and Form 20-F 2016

Notes on financial statements

1. Significant accounting policies, judgements, estimates and assumptions

Authorization of financial statements and statement of compliance with Financial Reporting Standard 101 ‘Reduced Disclosure
Framework’ (FRS 101)
The financial statements of BP p.l.c. for the year ended 31 December 2016 were approved and signed by the group chief executive on 6 April
2017 having been duly authorized to do so by the board of directors. The company meets the definition of a qualifying entity under Financial
Reporting Standard 100 ‘Application of Financial Reporting Requirements’ (FRS 100) issued by the Financial Reporting Council. Accordingly,
these financial statements have been prepared in accordance with FRS 101 and in accordance with the provisions of the UK Companies Act
2006.

Basis of preparation
The financial statements have been prepared on a going concern basis and in accordance with the Companies Act 2006 and applicable UK
accounting standards.

The financial statements have been prepared under the historical cost convention. Historical cost is generally based on the fair value of the
consideration given in exchange for the assets.

As permitted by FRS 101, the company has taken advantage of the disclosure exemptions available in relation to:

(a)
(b)

(e)
(f)

the requirements of IFRS 7 ‘Financial Instruments: Disclosures’;
the requirements of paragraphs 10(d), 10(f), 16, 38A, 38B, 38C, 38D, 40A, 40B, 40C, 40D, 111 and 134 to 136 of IAS 1 ‘Presentation of
Financial Statements’;
the requirements of IAS 7 ‘Statement of Cash Flows’;
the requirements of paragraphs 30 and 31 of IAS 8 ‘Accounting Policies, Changes in Accounting Estimates and Errors’ in relation to
standards not yet effective;
the requirements of paragraphs 17 and 18A of IAS 24 ‘Related Party Disclosures’; and
the requirements of IAS 24 ‘Related Party Disclosures’ to disclose related party transactions entered into between two or more members
of a group, provided that any subsidiary which is a party to the transaction is wholly owned by such a member.

Where required, equivalent disclosures are given in the consolidated financial statements of BP p.l.c.

As permitted by Section 408 of the Companies Act 2006, the income statement of the company is not presented as part of these financial
statements.

As permitted by FRS 101 from 1 January 2016, the company has adopted the balance sheet format set out in IAS 1 rather than the Companies
Act 2006 format that was previously used. This provides greater consistency with the consolidated financial statements.

The financial statements are presented in US dollars and all values are rounded to the nearest million dollars ($ million), except where otherwise
indicated.

Investments
Investments in subsidiaries are recorded at cost. The company assesses investments for impairment whenever events or changes in
circumstances indicate that the carrying amount 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.

Significant estimate or judgement: investments
The recoverable amount, which is often the fair value less costs to sell, may be based upon discounted future cash flows. The assumptions
underlying these calculations, such as the discount rate, future oil and gas prices, and other asset specific factors, are judgemental. Further
information on the assumptions that are used in such calculations is included in Note 1 to the consolidated financial statements.

Foreign currency translation
The functional and presentation currency of the financial statements is US dollars. Transactions in foreign currencies are initially recorded in the
functional currency by applying the spot exchange rate on the date of the transaction. Monetary assets and liabilities denominated in foreign
currencies are retranslated into the functional currency at the spot exchange rate on the balance sheet date. Any resulting exchange differences
are included in the income statement.

Exchange adjustments arising when the opening net assets and the profits for the year retained by a non-US dollar functional currency branch
are translated into US dollars are recognized in a separate component of equity and reported in other comprehensive income. Income statement
transactions are translated into US dollars using the average exchange rate for the reporting period.

Financial guarantees
The company enters into financial guarantee contracts with its subsidiaries. At the inception of a financial guarantee contract, a liability is
recognized initially at fair value and then subsequently at the higher of the estimated loss and amortized cost. Where a guarantee is issued for a
premium, a receivable of an amount equal to the liability is initially recognized. Subsequently, the liability and receivable reduce by the amount of
consideration received, which is recognized in the income statement. Where a guarantee is issued without a premium, the fair value is
recognized as additional investment in the entity to which the guarantee relates.

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

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1. Significant accounting policies, judgements, estimates and assumptions – continued

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 of the equity instruments on the date on which they 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.

For other equity-settled share-based payment transactions, the goods or services received and the corresponding increase in equity are
measured at the fair value of the goods or services received.

Pensions
The cost of providing benefits under the company’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, 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.

Contributions to defined contribution plans are recognized in the income statement in the period in which they become payable.

Significant estimate: pensions
Accounting for defined benefit pensions involves making significant estimates about uncertain events, including 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.

Pension 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 company’s balance sheet, and pension expense for the
following year. The assumptions used are provided in Note 4.

In addition to the financial assumptions, we regularly review the demographic and mortality assumptions. Mortality assumptions reflect best
practice in the UK and have been chosen with regard to applicable published tables adjusted where appropriate to reflect the experience of
the plan 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 4.

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.

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 company’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 assets are only recognized to the extent that it is probable that they will be realized in the future.

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

218

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1. Significant accounting policies, judgements, estimates and assumptions – continued

Significant estimate or judgement: deferred tax
Management judgement is required to determine the amount of deferred tax assets that can be recognized, based upon the likely timing and
level of future taxable profits.

Financial assets
All financial assets held by the company are classified as loans and receivables. Financial assets include cash and cash equivalents, receivables
and other investments. The company determines the classification of its financial assets at initial recognition. Financial assets are recognized
initially at fair value, normally being the transaction price plus directly attributable transaction costs.

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.
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 liabilities
All financial liabilities held by the company are classified as financial liabilities measured at amortized cost. Financial liabilities include other
payables, accruals, and most items of finance debt. The company determines the classification of its financial liabilities at initial recognition.

Financial liabilities measured at amortized cost
All financial liabilities are initially recognized at fair value, net of transaction costs. 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, 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 in interest and other income and finance costs respectively. This category of financial
liabilities includes payables and finance debt.

2. Investments

Cost

At 1 January 2016
Additions
Disposals

At 31 December 2016

Amounts provided

At 1 January 2016

At 31 December 2016

Cost

At 1 January 2015
Additions
Disposals

At 31 December 2015

Amounts provided

At 1 January 2015

At 31 December 2015

At 31 December 2016
At 31 December 2015

Subsidiaries

Associates

Total

$ million

139,313
32,833
(5,791)

166,355

139,313
2,800
(2,800)

139,313

166,281
139,239

2
–
–

–

2
–
–

–

2
2

139,315
32,833
(5,791)

166,357

139,315
2,800
(2,800)

139,315

166,283
139,241

The company increased its investment in BP Holdings North America Limited by $27,100 million and its investment in BP International Limited
by $5,727 million during 2016. It also disposed of its $5,727-million investment in BP Corporate Holdings Limited.

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

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2. Investments – continued

The more important subsidiaries of the company at 31 December 2016 and the percentage holding of ordinary share capital (to the nearest
whole number) are set out below. For a full list of related undertakings see Note 14.

Subsidiaries

International

BP Global Investments
BP International
Burmah Castrol

Canada

BP Holdings Canada

BP Holdings North America

Country of incorporation

Principal activities

100
100
100

England & Wales
England & Wales
Scotland

Investment holding
Integrated oil operations
Lubricants

100

England & Wales

Investment holding

100

England & Wales

Investment holding

The carrying value of the investment in BP International Limited at 31 December 2016 was $76,152 million (2015 $70,425 million).

3. Receivables

Amounts receivable from subsidiariesa
Amounts receivable from associates
Other receivables

2016

Non-
current

2,951
–
–

2,951

$ million

2015

Current

Non-current

1,054
5
3

1,062

–
–
–

–

Current

480
4
3

487

a 2016 non-current receivables includes a promissory note issued by BP (Abu Dhabi) Limited in consideration for the issue of BP p.l.c. ordinary shares to the government of Abu Dhabi. See Note

10 for further information.

4. Pensions

The primary pension arrangement is a funded final salary pension plan in the UK 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, 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 plan is closed to new joiners but remains open to ongoing accrual for current members. New joiners are eligible for membership of a
defined contribution plan.

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 2016 the aggregate level of contributions was $539 million (2015 $754 million). The aggregate level of contributions in 2017 is
expected to be approximately $652 million, and includes contributions we expect to be required to make by law or under contractual
agreements, as well as an allowance for discretionary funding.

For the primary 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 seven years is agreed. The funding agreement can be terminated unilaterally by either party with
two years’ notice. Contractually committed funding therefore represents nine years of future contributions, which amounted to $5,761 million at
31 December 2016, of which $2,410 million relates to past service. The surplus relating to the primary pension plan is recognized on the balance
sheet on the basis that the company is entitled to a refund of any remaining assets once all members have left the plan.

The obligation and cost of providing the pension benefits is assessed annually using the projected unit credit method. The date of the most
recent actuarial review was 31 December 2016. The principal plans are subject to a formal actuarial valuation every three years in the UK. The
most recent formal actuarial valuation of the primary pension plan was as at 31 December 2014.

The material financial assumptions used to estimate 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
Inflation for pension plan service costs

2016

2.7
4.6
3.0
3.0
3.2

2016

4.0
3.9
3.1

2015

3.9
4.4
3.0
3.0
3.0
%

2015

3.9
3.6
3.1

The 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 assumption is used to determine the rate of increase for pensions in payment and the rate of increase in

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

220

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4. Pensions – continued

deferred pensions. For 2016, the assumed rate of increase for the UK plans also reflects the probability of exceeding a cap or breaching a floor
for pension increases as set out in the plan rules; this change resulted in a reduction in the pension obligation of $865 million.

The 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 applicable published tables adjusted to reflect the experience of the plans and an
extrapolation of past longevity improvements into the future. For the primary pension plan the 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

2016

28.0
30.0
29.5
31.9

Years

2015

28.5
31.0
29.5
31.9

The assets of the primary 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.

For the primary 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 the asset portfolio with the pension liabilities. During 2016, the plan switched 4% from
equities to bonds.

The primary plan uses a liability driven investment (LDI) approach for part of the portfolio, a form of investing designed to match the movement
in pension plan assets with the impact of interest rate changes and inflation assumption changes on the projected benefit obligation.

The company’s asset allocation policy for the primary plan is as follows:

Asset category

Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate

58
35
7

F
n
a
n
c
a

In addition, the primary plan has entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $4,450
million (2015 $2,651 million) of the corporate bond portfolio. At 31 December 2016 the fair value liability of these swaps was $144 million (2015
$17 million fair value asset) and is included in other assets in the table below.

s
t
a
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e
m
e
n
t
s

The primary plan does not invest directly in either securities or property / real estate of the company or of any subsidiary.

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 222.

Fair value of pension plan assets

Listed equities – developed markets
– emerging markets

Private equity
Government issued nominal bondsa
Government issued index-linked bondsa
Corporate bondsa
Propertyb
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments

a Bonds held are denominated in sterling.
b Property held is all located in the United Kingdom.

2016

$ million

2015

11,494
2,549
2,754
489
9,384
4,042
1,970
547
(68)
(2,981)

30,180

13,474
2,305
2,933
393
6,425
4,357
2,453
564
110
(1,791)

31,223

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

221

4. Pensions – continued

Analysis of the amount charged to profit before interest and taxation

Current service costa
Past service costb

Operating charge relating to defined benefit plans

Payments to defined contribution plan

Total operating charge

Interest income on plan assetsc
Interest on plan liabilities

Other finance income (expense)

Analysis of the amount recognized in other comprehensive income

Actual asset return less interest income on pension plan assets
Change in financial assumptions underlying the present value of the plan liabilities
Change in demographic assumptions underlying the present value of plan liabilities
Experience gains and losses arising on the plan liabilities

Remeasurements recognized in other comprehensive income

2016

333
17

350

380

1,086
(1,004)

4,422
(6,926)
430
55

(2,019)

$ million

2015

485
12

497

528

1,124
(1,144)

(20)

315
2,054
–
321

2,690

a The costs of managing the fund’s investments are treated as being part of the investment return, the costs of administering our pensions plan benefits are included in current service cost.
b Past service cost represents the increased liability arising as a result of early retirements occurring as part of restructuring programmes.
c 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.

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 participantsa
Benefit payments (funded plans)b
Benefit payments (unfunded plans)b
Remeasurements

Benefit obligation at 31 December

Movements in fair value of plan assets during the year

Fair value of plan assets at 1 January
Exchange adjustments
Interest income on plan assetsc
Contributions by plan participantsa
Contributions by employers (funded plans)
Benefit payments (funded plans)b
Remeasurementsc

Fair value of plan assets at 31 Decemberd e

Surplus at 31 December

Represented by

Asset recognized
Liability recognized

The surplus 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

2016

$ million

2015

28,934
(5,680)
350
1,004
18
(1,192)
(4)
6,441

29,871

31,223
(5,916)
1,086
18
539
(1,192)
4,422

30,180

309

528
(219)

309

519
(210)

309

32,357
(1,446)
497
1,144
32
(1,269)
(6)
(2,375)

28,934

31,773
(1,506)
1,124
32
754
(1,269)
315

31,223

2,289

2,516
(227)

2,289

2,506
(217)

2,289

(29,661)
(210)

(28,717)
(217)

(29,871)

(28,934)

a Most of the contributions made by plan participants were made under salary sacrifice.
b The benefit payments amount shown above comprises $1,177 million benefits plus $19 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 interest income on plan assets and the remeasurement of plan assets as disclosed above.
d Reflects $29,970 million of assets held in the BP Pension Fund (2015 $31,030 million) and $165 million held in the BP Global Pension Trust (2015 $147 million), with $38 million representing

the company’s share of Merchant Navy Officers Pension Fund (2015 $37 million) and $7 million of Merchant Navy Ratings Pension Fund (2015 $9 million).

e The fair value of plan assets includes borrowings related to the LDI programme as described on page 221.

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

222

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4. Pensions – continued

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 2016 for the company’s plans would have had the effects shown in the
table below. The effects shown for the expense in 2017 comprise the total of current service cost and net finance income or expense.

Discount ratea

Effect on pension expense in 2017
Effect on pension obligation at 31 December 2016

Inflation rateb

Effect on pension expense in 2017
Effect on pension obligation at 31 December 2016

Salary growth

Effect on pension expense in 2017
Effect on pension obligation at 31 December 2016

$ million

One percentage point

Increase

Decrease

(288)
(5,294)

248
7,067

219
4,628

75
1,043

(185)
(4,085)

(66)
(947)

One additional year of longevity in the mortality assumptions would increase the 2017 pension expense by $38 million and the pension
obligation at 31 December 2016 by $1,092 million.

Estimated future benefit payments

2017
2018
2019
2020
2021
2022-2026

Weighted average duration

5. Payables

Amounts payable to subsidiaries
Accruals and deferred income
Other payables

$ million

904
947
984
1,003
1,039
5,576
Years

20.4

$ million

2015

Non-
current

6,708
33
–

6,741

2016

Non-
current

34,389
43
–

34,432

Current

3,904
129
192

4,225

Current

100
81
31

212

Included in non-current amounts payable to subsidiaries after one year is an interest-bearing payable of $4,236 million (2015 $4,236 million) with
BP International Limited, with interest being charged based on a 3 month USD LIBOR rate plus 55 basis points and a maturity date of December
2021. Also included is an interest-bearing payable of $2,300 million (2015 $2,311 million) with BP Finance plc, with interest being charged based
on a 1 year USD LIBOR rate and a maturity date of April 2020. Non-current amounts payable to subsidiaries also includes an interest-bearing
payable of $27,100 million (2015 $nil) with BP International Limited with interest being charged based on a 3 month USD LIBOR rate plus 65
basis points and a maturity date of May 2023.

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 payables.

Due within

1 to 2 years
2 to 5 years
More than 5 years

2016

206
6,936
27,290
34,432

$ million

2015

75
85
6,581
6,741

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

223

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6. Taxation

Tax charge included in total comprehensive income

Deferred tax

Origination and reversal of timing differences in the current year

This comprises:

Taxable temporary differences relating to pensions

Deferred tax

Deferred tax liability

Pensions

Net deferred tax liability

Analysis of movements during the year

At 1 January
Charge for the year on ordinary activities
Charge (credit) for the year in other comprehensive income

At 31 December

2016

(698)

179

877
52
(750)

179

$ million

2015

877

–
81
796

877

At 31 December 2016, deferred tax assets of $82 million on other temporary differences and $8 million relating to pensions (2015 $65 million
relating to other temporary differences and $8 million relating to pensions) were not recognized as it is not considered probable that suitable
taxable profits will be available in the company from which the future reversal of the underlying temporary differences can be deducted. It is
anticipated that the reversal of these temporary differences will benefit other group companies in the future.

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 – otherb

31 December

Shares
thousand

7,233
5,473

20,108,771
548,005
392,920

21,049,696

2016

$ million

12
9

5,028
137
98

5,263

5,284

Shares
thousand

7,233
5,473

20,005,961
102,810
–

20,108,771

2015

$ million

12
9

5,002
26
–

5,028

5,049

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 Relates to the issue of new ordinary shares to the government of Abu Dhabi. See Notes 3 and 10 for further information.

Treasury sharesa

At 1 January
Purchases for settlement of employee share plans
Shares re-issued for employee share-based payment plans

At 31 December

Of which – shares held in treasury by BP

– shares held in ESOP trusts
– shares held by BP’s US plan administratorb

2016

2015

Shares
thousand

Nominal value
$ million

Shares
thousand

Nominal value
$ million

1,756,327
9,631
(151,339)

1,614,619

1,576,411
21,432
16,814

439
2
(38)

403

394
5
4

1,811,297
51,142
(106,112)

1,756,327

1,727,763
18,453
10,111

453
13
(27)

439

432
4
3

a See Note 8 for definition of treasury shares.
b Held by the company in the form of ADSs to meet the requirements of employee share-based payment plans in the US.

For each year presented, the balance at 1 January represents the maximum number of shares held in treasury by BP during the year,
representing 8.6% (2015 8.9%) of the called-up ordinary share capital of the company.

During 2016, the movement in shares held in treasury by BP represented less than 0.8% (2015 less than 0.2%) of the ordinary share capital of
the company.

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

224

BP Annual Report and Form 20-F 2016

8. Capital and reserves

See statement of changes in equity for details of all reserves balances.

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.

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) and by BP’s US share plan administrator 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 company 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
company.

Foreign currency translation reserve
The foreign currency translation reserve records exchange differences arising from the translation of the financial information of the foreign
currency branch. Upon disposal of foreign operations, the related accumulated exchange differences are recycled to the income statement.

Profit and loss account
The balance held on this reserve is the accumulated retained profits of the company.

The profit and loss account reserve includes $24,107 million (2015 $24,107 million), the distribution of which is limited by statutory or other
restrictions.

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9. Financial guarantees

The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2016 were $71,443 million (2015 $51,775
million), the majority of which relate to finance debt of subsidiaries. The increase in 2016 primarily relates to guarantees of subsidiaries’ liabilities
under the Consent Decree between the United States, the Gulf states and BP and under the settlement agreement with the Gulf states in
relation to the Gulf of Mexico oil spill. The company has also issued uncapped indemnities and guarantees, including a guarantee of subsidiaries’
liabilities under the Plaintiffs’ Steering Committee agreement relating to the Gulf of Mexico oil spill. Uncapped indemnities and guarantees are
also issued in relation to potential losses arising from environmental incidents involving ships leased and operated by a subsidiary.

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10. 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

2016

397
44
441

59
48

$ million

2015

759
(50)
709

32
–

In addition to the share-based payment transactions detailed in the table above, the company issued ordinary shares to the government of Abu
Dhabi in consideration for a 10% interest in the Abu Dhabi onshore oil concession. The interest in the concession is owned by a subsidiary of the
company, BP (Abu Dhabi) Limited. As part of the agreements BP (Abu Dhabi) Limited has issued a promissory note to the company as described
in Note 3. The share-based payment transaction was valued at the fair value of the interest in the assets, which was valued with reference to a
market transaction for an identical interest.

Additional information on the company’s share-based payment plans is provided in Note 10 to the consolidated financial statements.

11. Auditor’s remuneration

Note 35 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a group basis.

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

225

12. Directors’ remuneration

Remuneration of directors

Total for all directors

Emoluments
Amounts awarded under incentive schemesa

Total

a Excludes amounts relating to past directors.

2016

10
14

$ million

2015

10
14

13. Employee costs and numbers

Employee costs

Wages and salaries
Social security costs
Pension costs

Average number of employees

Upstream
Downstream
Other businesses and corporate

2016

480
66
69

615

2016

248
1,152
2,405

3,805

$ million

2015

478
67
96

641

2015

259
1,395
2,424

4,078

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

226

BP Annual Report and Form 20-F 2016

14. Related undertakings of the group

In accordance with Section 409 of the Companies Act 2006, a full list of related undertakings, the registered office address and the percentage
of equity owned as at 31 December 2016 is disclosed below.

Unless otherwise stated, the share capital disclosed comprises ordinary shares or common stock (or local equivalent thereof) which are
indirectly held by BP p.l.c.

All subsidiary undertakings are controlled by the group and their results are fully consolidated in the group’s financial statements.

The percentage of equity owned by the group is 100% unless otherwise noted below.

The stated ownership percentages represent the effective equity owned by the group.

Subsidiaries
200 PS Overseas Holdings Inc.
4321 North 800 West LLCa
563916 Alberta Ltd.
ACP (Malaysia), Inc.
Actomat B.V.
Advance Petroleum Holdings Pty Ltd
Advance Petroleum Pty Ltd
AE Cedar Creek Holdings LLCa
AE Goshen II Holdings LLCa
AE Goshen II Wind Farm LLCa
AE Power Services LLCa
AE Wind PartsCo LLCa
Air BP Albania SHA
Air BP Brasil Ltda.
Air BP Canada LLCa
Air BP Croatia d.o.o.
Air BP Denmark ApS
Air BP Finland OYb
Air BP Limited
Air BP Norway AS
Air BP Sales Romania S.R.L.
Air BP Sweden AB
Air Refuel Pty Ltdc
Allgreen Pty Ltd
AM/PM International Inc.
American Oil Company
Amoco (Fiddich) Limited
Amoco (U.K.) Exploration Company, LLC
Amoco Austria Petroleum Company
Amoco Bolivia Petroleum Company
Amoco Bolivia Services Company Inc.
Amoco Brazil, Inc.
Amoco Canada International Holdings B.V.
Amoco Capline Pipeline Company
Amoco Chemical (Europe) S.A.
Amoco Chemical Holding B.V.d
Amoco Chemical U.K. Limited (in liquidation)
Amoco Chemicals (FSC) B.V.
Amoco CNG (Trinidad) Limited
Amoco Cypress Pipeline Company
Amoco Destin Pipeline Company
Amoco Endicott Pipeline Company
Amoco Environmental Services Company
Amoco Exploration Holdings B.V.
Amoco Fabrics (U.K.) Limited (in liquidation)
Amoco Fabrics and Fibers Ltd.e
Amoco Guatemala Petroleum Company
Amoco International Finance Corporation
Amoco International Petroleum Company
Amoco Kazakhstan (CPC) Inc.
Amoco Leasing Corporation
Amoco Louisiana Fractionator Company
Amoco Main Pass Gathering Company
Amoco Marketing Environmental Services Company
Amoco MB Fractionation Company
Amoco MBF Company
Amoco Netherlands Petroleum Company
Amoco Nigeria Exploration Company Limitedf
Amoco Nigeria Oil Company Limitedf
Amoco Nigeria Petroleum Company
Amoco Nigeria Petroleum Company Limited
Amoco Norway Oil Company
Amoco Oil Holding Company
Amoco Olefins Corporation
Amoco Overseas Exploration Company
Amoco Pipeline Asset Company
Amoco Pipeline Holding Company
Amoco Properties Incorporated
Amoco Realty Company
Amoco Remediation Management Services Corporation
Amoco Research Operating Company
Amoco Rio Grande Pipeline Company
Amoco Somalia Petroleum Company
Amoco Sulfur Recovery Company
Amoco Tax Leasing X Corporation
Amoco Trinidad Gas B.V.
Amoco Tri-States NGL Pipeline Company
The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Aeroporti Nderkombetar i Tiranes, “Nene Tereza”, Post Box 2933 in Tirana, Albania
Avenida Rouxinol, 55 , Offices 501-514 , Moema Office Tower, São Paulo, 04516 - 000, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Petrinjska ulica 2, Zagreb, Croatia
Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark
Teknobulevardi 3-5, 01530 Vantaa, Finland
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Drammensveien 167, Oslo, 0277, Norway
59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania
Box 8107, 10420, Stockholm, Sweden
Bulwer Island Refinery, 572 Curtin Avenue, Eagle Farm QLD 4009, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
5-5A Queen’s Park West, Port-of-Spain, Trinidad and Tobago
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Bank of America Center, 16th Floor, 1111 East Main Street, Richmond VA 23219, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1423 Cameron Street, Hawkesbury ON, Canada
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
400 East Court Avenue, Des Moines IA 50309, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States

BP Annual Report and Form 20-F 2016

227

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14. Related undertakings of the group – continued

Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
801 Adlai Stevenson Drive, Springfield, IL, 62703, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Wittener Straße 45, 44789 Bochum, Germany
Bâtiment B, 36 route de Longwy, L-8080 Bertrange, Luxembourg
Wittener Straße 45, 44789 Bochum, Germany
Autoroute A3/E25, L-3325 Brechem Ouest, Luxembourg
Bâtiment B, 36 route de Longwy, L-8080 Bertrange, Luxembourg
Überseeallee 1, 20457, Hamburg, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Rua da Candelária, 65, Office 2102, Rio de Janeiro, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
Providence House, East Hill Street, P.O. Box N-3944, Nassau, Bahamas
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States

Amoco U.K. Petroleum Limited
AmProp Finance Company
Amprop Illinois I Limited Partnershipg
Amprop, Inc.
Anaconda Arizona, Inc.
Aral Aktiengesellschaft
Aral Luxembourg S.A.
Aral Mineralölvertrieb GmbH
Aral Services Luxembourg Sarl
Aral Tankstellen Services Sarl
Aral Vertrieb GmbH
ARCO British International, Inc.
ARCO British Limited, LLC
ARCO Coal Australia Inc.
Arco do Brasil Ltda.
ARCO El-Djazair Holdings Inc.
ARCO El-Djazair LLCa
ARCO Environmental Remediation, L.L.C.a
ARCO Exploration, Inc.
ARCO Gaviota Company
ARCO Ghadames Inc.
ARCO International Investments Inc.
ARCO International Services Inc.
ARCO Material Supply Company
ARCO Midcon LLCa
ARCO Neftegaz Holdings, Inc.
ARCO Oil Company Nigeria Unlimiteda
ARCO Oman Inc.
ARCO Products Company
ARCO Resources Limited
ARCO Terminal Services Corporation
ARCO Trinidad Exploration and Production Company Limited Providence House, East Hill Street, P.O. Box N-3944, Nassau, Bahamas
ARCO Unimar Holdings LLCa
Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%)
Atlantic 2/3 UK Holdings Limited
Atlantic Richfield Company
Autino Holdings Limitedh
Auwahi Wind Energy Holdings LLCa
Bahia de Bizkaia Electridad, S.L. (75.00%)
Baltimore Ennis Land Company, Inc.
Black Lake Pipe Line Company
BP - Castrol (Thailand) Limited (57.56%)b
BP (Abu Dhabi) Limited
BP (Barbados) Holding SRL
BP (Barbican) Limitedi
BP (China) Holdings Limited
BP (China) Industrial Lubricants Limited
BP (Gibraltar) Limitedj
BP (Indian Agencies) Limitedi
BP (Malta) Limitedi
BP (Shanghai) Trading Limited
BP Absheron Limited
BP Africa Limitedi
BP Akaryakit Ortakligi (70.00%)g
BP Alaska LNG LLCa
BP Alternative Energy Holdings Limited
BP Alternative Energy North America Inc.
BP America Chembel Holding LLC
BP America Chemicals Company
BP America Foreign Investments Inc.
BP America Inc.
BP America Limited
BP America Production Company
BP AMI Leasing, Inc.
BP Amoco Chemical Company
BP Amoco Chemical Holding Company
BP Amoco Chemical Indonesia Limited
BP Amoco Chemical Malaysia Holding Company
BP Amoco Chemical Singapore Holding Company
BP Amoco Exploration (Faroes) Limited
BP Amoco Exploration (In Amenas) Limited
BP Amoco Neighborhood Development Corporation
BP Angola (Block 18) B.V.
BP Argentina Exploration Company
BP Aromatics Holdings Limited
BP Aromatics Limited
BP Aromatics Limited N.V.
BP Asia Limited
BP Asia Pacific (Malaysia) Sdn. Bhd.
BP Asia Pacific Holdings Limited
BP Asia Pacific Pte Ltdi
BP Australia Capital Markets Limited
BP Australia Employee Share Plan’ Proprietary Limited
BP Australia Group Pty Ltdf
BP Australia Investments Pty Ltd
BP Australia Nominees Proprietary Limited
BP Australia Pty Ltd
BP Australia Shipping Pty Ltdk
BP Australia Swaps Management Limited
BP Aviation A/S
BP Benevolent Fund Trustees Limitedi

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
83-85 London Street , Reading , Berkshire, RG1 4QA, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Atraque Punta Lucero, Explanada Punta Ceballos s/n, Ziérbena (Vizcaya), Spain
1300 East Ninth Street, Cleveland, OH, 44114, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Erin Court, Bishop’s Court Hill, St. Michael, Barbados
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Room 2101, 21F Youyou International Plaza, 76 Pujian Road, Pudong, Shanghai, PRC
Bin Jiang Road, Petrochemical Industrial Park, Jiangsu Province, China
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
3rd Floor, Navi Buildings, Pantar Road, Lija, LJA 2021, Malta
Room 2206, Dong Hua Financial Building, 28 Ma ji Road, Waigaoqiao Bonded Zone, Shanghai, China
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Degirmen yolu cad. No:28, Asia OfisPark K:3 I˙cerenkoy-Atasehir, Istanbul, 34752, Turkey
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
400 East Court Avenue, Des Moines IA 50309, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Amocolaan 2 2440 Geel, Belgium
Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong
Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
c/o Danish Refuelling Services, Kastrup Lufthavn, 2770 Kastrup, Denmark
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

228

BP Annual Report and Form 20-F 2016

14. Related undertakings of the group – continued

BP Berau Ltd.
BP Biocombustíveis S.A. (99.99%)
BP Bioenergia Campina Verde Ltda. (99.99%)
BP Bioenergia Ituiutaba Ltda. (99.99%)
BP Bioenergia Itumbiara S.A. (99.99%)
BP Bioenergia Tropical S.A. (99.99%)
BP Biofuels Advanced Technology Inc.
BP Biofuels Brazil Investments Limited
BP Biofuels Louisiana LLCa
BP Biofuels North America LLCa
BP Biofuels Trading Comércio, Importação e Exportação
Ltda. (99.99%)
BP Biofuels UK Limited
BP Bomberai Ltd.
BP Brasil Investimentos Ltda
BP Brasil Ltda.
BP Brazil Tracking L.L.C.a
BP Bulwer Island Pty Ltdl
BP Business Service Centre Asia Sdn Bhd

BP Business Service Centre KFTa
BP Canada Energy Development Company
BP Canada Energy Group ULC
BP Canada Energy Marketing Corp.
BP Canada International Holdings B.V.
BP Canada Investments Inc.
BP Capellen Sarl
BP Capital Markets America Inc.
BP Capital Markets p.l.c.
BP Caplux S.A.c
BP Car Fleet Limitedi
BP Caribbean Company
BP Castrol KK (64.84%)
BP Castrol Lubricants (Malaysia) Sdn. Bhd. (63.03%)
BP Chembel N.V.
BP Chemical US Sales Company
BP Chemicals (Korea) Limited
BP Chemicals East China Investments Limited
BP Chemicals France Holding
BP Chemicals Investments Limited
BP Chemicals Limited
BP Chemicals Trading Limited
BP Chile Petrolera Limitada
BP China Exploration and Production Company
BP China Limitedi
BP Company North America Inc.
BP Containment Response Limited
BP Containment Response System Holdings LLCa
BP Continental Holdings Limited
BP Corporate Holdings Limited
BP Corporation North America Inc.b
BP Danmark A/S
BP Developments Australia Pty. Ltd.
BP Dogal Gaz Ticaret Anonim Sirketi
BP East Kalimantan CBM Limited
BP Eastern Mediterranean Limitedi
BP Egypt Company
BP Egypt East Delta Marine Corporation
BP Egypt East Tanka B.V.
BP Egypt Production B.V.
BP Egypt Ras El Barr B.V.
BP Egypt West Mediterranean (Block B) B.V.
BP Energía México, S. de R.L. de C.V.
BP Energy Asia Pte. Limited
BP Energy Colombia Limited
BP Energy Company
BP Energy do Brasil Ltda.
BP Energy Europe Limited
BP Espana, S.A. Unipersonall
BP Europa SEm
BP Exploracion de Venezuela S.A.

BP Exploration & Production Inc.e
BP Exploration (Alaska) Inc.
BP Exploration (Algeria) Limited
BP Exploration (Alpha) Limited
BP Exploration (Angola) Limited
BP Exploration (Azerbaijan) Limited
BP Exploration (Canada) Limited
BP Exploration (Caspian Sea) Limited
BP Exploration (Delta) Limited
BP Exploration (El Djazair) Limited
BP Exploration (Epsilon) Limited
BP Exploration (Finance) Limited
BP Exploration (Greenland) Limited
BP Exploration (Morocco) Limited
BP Exploration (Namibia) Limited
BP Exploration (Nigeria Finance) Limited
BP Exploration (Nigeria) Limited
BP Exploration (Shafag-Asiman) Limited
BP Exploration (Shah Deniz) Limited

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida das Nações Unidas, 12.399, 4º andar, cj. 41B, sala 01, São Paulo, Brazil
Rua Principal, Fazenda Recanto, Caixa Postal 01, Ituiutaba, Minas Gerais, 38.300-898, Brazil
Fazenda Recanto, Zona Rural, CEP 38.300-898, Ituiutaba, Minas Gerais, Brazil
Estrada Municipal Itumbiara, Chacoeira Dourada, Fazenda Jandaia, Itumbiara, Goiás, 75516-126, Brazil
Rodovia GO 410, km 51 à esquerda, Fazenda Canadá, s/n, Zona Rural, Edéia, Goiás, 75940-000, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida das Nações Unidas, 12.399, 4º andar, cj. 41B, sala 01, São Paulo, Brazil

Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rua Bernardo Guimarães, 135, part, Rio de Janeiro, Brazil
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur,
Malaysia
BP Business Service Centre KFT, 32-34 Soroksári út, H-1095 Budapest, Hungary
Stewart McKelvey, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada
Stewart McKelvey, 900, 1959 Upper Water Street, Halifax NS B3J 3N2, Canada
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Aire de Capellen, L-8309 Capellen, Luxembourg
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Aire de Capellen, L-8309 Capellen, Luxembourg
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
East Tower 20F, Gate CIty Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan
Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia
Amocolaan 2 2440 Geel , Belgium
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
150 West Market Street, Suite 800, Indianapolis IN 46204, United States
Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark
Level 8, 250 St Georges Terrace, Perth WA 6000, Australia
Degirmen yolu cad. No:28, Asia OfisPark K:3 I˙cerenkoy-Atasehir, Istanbul, 34752, Turkey
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain
Überseeallee 1, 20457, Hamburg, Germany
Av. Francisco de Miranda, Edif Cavendes, Los Palos Grandes, Chacao, Caracas Miranda, 1060,
Venezuela
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Providence House, East Hill Street, P.O. Box N-3910, Nassau, Bahamas
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Landmark Towers-5B, Water Corporation Road, Victoria Island, Lagos, Nigeria
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

229

F
n
a
n
c
a

s
t
a
t
e
m
e
n
t
s

14. Related undertakings of the group – continued

BP Exploration (South Atlantic) Limited
BP Exploration (Vietnam) Limited
BP Exploration (West Africa) Limited
BP Exploration (Xazar) PTE. Ltd.
BP Exploration Angola (Kwanza Benguela) Limited
BP Exploration Australia Pty Ltd
BP Exploration Beta Limited
BP Exploration China Limited
BP Exploration Company (Middle East) Limited
BP Exploration Company Limitedn
BP Exploration do Brasil Ltda
BP Exploration Indonesia Limited
BP Exploration Libya Limited
BP Exploration Mexico Limited
BP Exploration Mexico, S.A. DE C.V.b

BP Exploration North Africa Limited
BP Exploration Operating Company Limitedl
BP Exploration Orinoco Limited
BP Exploration Personnel Company Limited
BP Express Shopping Limited
BP Finance Australia Pty Ltd
BP Finance p.l.c.
BP Foundation Incorporateda
BP France
BP Fuels & Lubricants AS
BP Fuels Deutschland GmbH
BP Gas Europe, S.A.U.
BP Gas Marketing Limited
BP Gas Supply (Angola) LLCa
BP Gelsenkirchen GmbH
BP Ghana Limited
BP Global Investments Limitedi
BP Global Investments Salalah & Co LLC
BP Global West Africa Limited
BP Greece Limited
BP Guangdong Limited (90.00%)
BP High Density Polyethylene France - BP HDPE
BP Holdings (Thailand) Limited (81.01%)o
BP Holdings B.V.
BP Holdings Canada Limitedi
BP Holdings International B.V.
BP Holdings North America Limitedi
BP Hong Kong Limited
BP India Services Private Limited
BP Indonesia Investment Limited
BP Indonesia Oil Terminal Investment Limited
BP International Limitedi
BP International Services Company
BP Investment Management Limited
BP Investments Asia Limited
BP Iran Limited
BP Iraq N.V.
BP Italia SpA
BP Japan K.K.
BP Kapuas I Limited
BP Kapuas II Limited
BP Kapuas III Limited
BP Korea Limited
BP Kuwait Limited
BP Latin America LLCa
BP Lesotho (Pty) Limitedi
BP Lingen GmbH
BP LNG Shipping Limited
BP Lubes Marketing GmbH
BP Lubricants KK (64.84%)
BP Lubricants USA Inc.
BP Luxembourg S.A.
BP Malaysia Holdings Sdn. Bhd. (70.00%)
BP Management International B.V.
BP Management Netherlands B.V.
BP Marine Limited
BP Maritime Services (Isle of Man) Limited
BP Maritime Services (Singapore) Pte. Limited
BP Marketing Egypt LLC
BP Mauritius Limited
BP Middle East Enterprises Corporationb
BP Middle East Limitedi
BP Middle East LLC
BP Mocambique Limitada
BP Mocambique Limited
BP Muturi Holdings B.V.
BP Nederland Holdings BV
BP Netherlands Exploration Holding B.V.
BP Netherlands Upstream B.V.
BP New Ventures Middle East Limited
BP New Zealand Holdings Limited
BP New Zealand Share Scheme Limited
BP Norge AS
BP Nutrition Inc.
BP Offshore Gathering Systems Inc.

Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 8, 250 St Georges Terrace, Perth WA 6000, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. CuajimalpaC.P., 05349 México D.F.,
Mexico
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 17, 717 Bourke Street, Docklands VIC, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France
P.O.Box 153 Skøyen, 0212 Oslo, Norway
Wittener Straße 45, 44789 Bochum, Germany
Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Pawikerstraße 30, 45899 Gelsenkirchen, Germany
Number 12, Aviation Road, Una Home 3rd Floor, Airport City , Accra, Greater Accra, PMB CT 42, Ghana
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
PO Box 2309, Salalah, 211, Oman
Landmark Towers - 5B, Water Corporation Road, Victoria Island, Lagos, Nigeria
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Rm 2710Guangfa Bank Plaza, No. 83 Nonglin Xia Road, Yuexiu District, Guangzhou, China
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France
39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong
Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Amocolaan 2 2440 Geel , Belgium
Via A. Cechov 50/2, 20151 Milan, Italy
Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
2nd Floor, Woojin Bldg., 76-4, Jamwon-dong, Seocho-gu, Seoul 137-909, Republic of Korea
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
BP House, Motsoene Road, Industrial Area, Maseru, Lesotho
Raffineriestraße, 49808 Lingen, Germany
c/o Codan Services Limited, PO Box HM 1022, Clarendon House, Church Street, Hamilton, Bermuda
Überseeallee 1, 20457, Hamburg, Germany
East Tower 20F, Gate CIty Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Aire de Capellen, L-8309 Capellen, Luxembourg
Axiata Tower, No.9 Jalan Stesen Sentral 5, Kuala Lumpur Sentral 50470 Kuala Lumpur, Malaysia
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Samuel Harris House, 5-11 St Georges Street, Douglas, Isle of Man, IM1 1AJ, Isle of Man
1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore
Plot 28, North 90 Road, Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt
5th Floor, Ebene Esplanade, 24 Cybercity, Ebene, Mauritius
Craigmuir Chambers, P.O. Box 71, Road Town, Tortola, British Virgin Islands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
P.O.Box 1699, Dubai, 1699, United Arab Emirates
Society and Geography Avenue, Plot No. 269 , Third floor, Maputo, Mozambique
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Godesetdalen 8, 4065 Stavanger, Norway
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

230

BP Annual Report and Form 20-F 2016

14. Related undertakings of the group – continued

BP Offshore Pipelines Inc.
BP Offshore Response Company LLCa
BP Oil (Thailand) Limited (90.32%)p
BP Oil and Chemicals International Philippines Inc.
BP Oil Australia Pty Ltd
BP Oil Espana, S.A. Unipersonal
BP Oil Hellenic S.A.
BP Oil International Limited
BP Oil Kent Refinery Limited (in liquidation)
BP Oil Llandarcy Refinery Limited
BP Oil Logistics UK Limited
BP Oil Marketing GmbH
BP Oil New Zealand Limited
BP Oil Pipeline Company
BP Oil Shipping Company, USA
BP Oil UK Limited
BP Oil Venezuela Limited
BP Oil Vietnam Limited
BP Oil Yemen Limited
BP Olex Fanal Mineralol GmbH
BP Pacific Investments Ltd
BP Pakistan (Badin) Inc.
BP Pakistan Exploration and Production, Inc.
BP Pension Trustees Limitedi
BP Pensions (Overseas) Limitedj
BP Pensions Limitedi
BP Petrochemicals India Investments Limited
BP Petroleo y Gas, S.A.

BP Petrolleri Anonim Sirketi
BP Pipelines (Alaska) Inc.
BP Pipelines (BTC) Limited
BP Pipelines (North America) Inc.
BP Pipelines (SCP) Limited
BP Pipelines (TANAP) Limited
BP Pipelines TAP Limited
BP Polska Services Sp. z o.o.
BP Portugal -Comercio de Combustiveis e Lubrificantes SA
BP Poseidon Limited
BP Products North America Inc.
BP Properties Limitedi
BP Raffinaderij Rotterdam B.V.
BP Refinery (Kwinana) Proprietary Limited
BP Refining & Petrochemicals GmbH
BP Regional Australasia Holdings Pty Ltd
BP Russian Investments Limited
BP Services International Limited
BP Shafag-Asiman Limited
BP Shipping Limited
BP Singapore Pte. Limited
BP Solar Energy North America LLCa
BP Solar Espana, S.A. Unipersonalc
BP Solar International Inc.
BP Solar Pty Ltd
BP South East Asia Limitedi
BP Southern Africa Proprietary Limited (75.00%)
BP Southern Cone Company
BP Subsea Well Response (Brazil) Limited
BP Subsea Well Response Limited
BP Taiwan Marketing Limited
BP Tanjung IV Limited
BP Technology Ventures Inc.
BP Technology Ventures Limited
BP Toplivnaya Kompanya LLCa
BP Trade and Supply (Germany) GmbH,Hamburg
BP Trading Limitedi
BP Train 2/3 Holding SRL
BP Transportation (Alaska) Inc.
BP Trinidad and Tobago LLC (70.00%)a
BP Trinidad Processing Limited
BP Turkey Refining Limitedi
BP Venezuela Investments B.V.
BP West Aru I Limited
BP West Aru II Limited
BP West Coast Products LLCa
BP West Papua I Limited
BP West Papua III Limited
BP Wind Energy North America Inc.
BP Wiriagar Ltd.
BP World-Wide Technical Services Limited
BP Zhuhai Chemical Company Limited (85.00%)
BP+Amoco International Limitedi
BPA Investment Holding Company
BPNE International B.V.
BPRY Caribbean Ventures LLC (70.00%)a
Brian Jasper Nominees Pty Ltd
Britannic Energy Trading Limited
Britannic Investments Iraq Limited (90.00%)
Britannic Strategies Limited
Britannic Trading Limited
British Pipeline Agency Limited (50.00%)b q

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand
30/F LKG Tower, 6801 Ayala Avenue, Makati City 1226, Philippines
Level 17, 717 Bourke Street, Docklands VIC, Australia
Polígono Industrial “El Serrallo”, s/n12100 Grao de Castellón, Castellón de la Plana, Spain
26 Kifissias Ave. and 2 Paradissou st., 15125 Maroussi, Athens, Greece
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Wittener Straße 45, 44789 Bochum, Germany
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Überseeallee 1, 20457, Hamburg, Germany
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Albert House, South Esplanade, St. Peter Port, GY1 1AW, Guernsey
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Francisco de Miranda, Edif Cavendes, Los Palos Grandes, Chacao, Caracas Miranda, 1060,
Venezuela
Degirmen yolu cad. No:28, Asia Ofis Park K:3 I˙cerenkoy-Atasehir, Istanbul, 34752, Turkey
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
45 Memorial Circle, Augusta ME 04330, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Ul. Jasnogórska 1, 31-358 Kraków, Malopolskie, Poland
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
351 West Camden Street, Baltimore MD 21201, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d’Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Level 17, 717 Bourke Street, Docklands VIC, Australia
Wittener Straße 45, 44789 Bochum, Germany
Level 17, 717 Bourke Street, Docklands VIC, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Harbour Front Avenue, #02-01 Keppel Bay Tower, Singapore 098632, Singapore
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
7FNo. 71Sec. 3Min Sheng East Road, Taipei, Taiwan
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
2 Paveletskaya sq, Building1, 115054 Moscow, Russian Federation
Überseeallee 1, 20457, Hamburg, Germany
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Erin Court, Bishop’s Court Hill, St. Michael , Barbados
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
5-5A Queen’s Park West, Port-of-Spain, Trinidad and Tobago
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Da Ping Harbour, Lin Gang Industrial Zone, Zhuhai City, Guangdong Province, China
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

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14. Related undertakings of the group – continued

Britoil Limited
BTC Pipeline Holding Company Limited
Burmah Castrol Australia Pty Ltdr
Burmah Castrol Holdings Inc.
Burmah Castrol PLCi
Burmah Castrol South Africa (Pty) Limited
Burmah Chile S.A.
Burmah Fuels Australia Pty Ltdl
BXL Plastics Limited
Cadman DBP Limited
Cape Vincent Wind Power, LLCa
Casitas Pipeline Company
Castrol (China) Limited
Castrol (Ireland) Limited
Castrol (Shenzhen) Company Limited
Castrol (U.K.) Limited
Castrol Australia Pty. Limited
Castrol Austria GmbHa
Castrol B.V.
Castrol BP Petco Limited Liability Company (65.00%)a
Castrol Brasil Ltda.
Castrol Caribbean & Central America Inc.
Castrol Colombia Limitada
Castrol Del Peru S.A. (99.49%)
Castrol Hungária Trading Co. Ltd. (Castrol Hungária
Kereskedelmi Kft)a
Castrol India Limited (51.00%)
Castrol Industrial North America Inc.
Castrol Industrie und Service GmbH
Castrol KK (64.84%)
Castrol Limited
Castrol Lubricants (CR), s.r.o.
Castrol Lubricants RO S.R.L
Castrol Mexico, S.A. de C.V.s

Castrol Namibia (Pty) Limited
Castrol Offshore Limited
Castrol Pakistan (Private) Limited
Castrol Philippines, Inc.
Castrol Servicos Ltda.
Castrol Slovensko, s.r.o.
Castrol South Africa Proprietary Limited
Castrol Ukraine LLCa
Castrol Zimbabwe (Private) Limited
Centrel Pty Ltd
CH-Twenty Holdings LLCa
CH-Twenty, Inc.
Clarisse Holdings Pty Ltd
Coastwise Trading Company, Inc.
Consolidada de Energia y Lubricantes, (CENERLUB) C.A.
Conti Cross Keys Inn, Inc.
Coro Trading NZ Limited
Cuyama Pipeline Company
Delta Housing Inc.
Dermody Developments Pty Ltd
Dermody Holdings Pty Ltd
Dermody Investments Pty Ltd
Dermody Petroleum Pty. Ltd.
DHC Solvent Chemie GmbH
Dome Beaufort Petroleum Limited
Dome Beaufort Petroleum Limited (March 1980) Limited
Partnershipg
Dome Beaufort Petroleum Limited 1979 Partnership No. 1g
Dome Wallis (1980) Limited Partnership (92.50%)g
Dradnats, Inc.
ECM Markets SA (Pty) Ltd (75.00%)
Edom Hills Project 1, LLCa
Elite Customer Solutions Pty Ltd
Elm Holdings Inc.
Energy Global Investments (USA) Inc.
Enstar LLCa
Europa Oil NZ Limited
Exomet, Inc.
Expandite Contract Services Limited
Exploration (Luderitz Basin) Limited
Exploration Service Company Limited
F&H Pipeline Company
Flat Ridge 2 Holdings LLCa
Flat Ridge Wind Energy, LLCa
Foseco Chile Ltda.
Foseco Holding International B.V.
Foseco Holding, Inc.
Foseco, Inc.
Fosroc Expandite Limited
Fosven, CA

Fowler Ridge Holdings LLCa
Fowler Ridge I Land Investments LLCa
Fowler Ridge II Holdings LLCa
Fowler Ridge III Wind Farm LLCa
FreeBees B.V.

1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa
José Musalen Saffie, Huerfanos N° 770 Of. 301, Santiago, Chile
Level 17, 717 Bourke Street, Docklands VIC, Australia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
111 Eighth Avenue, New York, New York, 10011, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong
First Floor, Fitzwilton House, Wilton Place, Dublin 2, Ireland
No.1120 Mawan Rod, Nanshan District, China
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Level 17, 717 Bourke Street, Docklands VIC, Australia
Straße 6, Objekt 17, Industriezentrum NÖ-Süd 2355 Wr. Neudorf, Austria
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
22-36 Nguyen Hue Street, 57-69F Dong Khoi Street, District 1, Ho Chi Minh City, Vietnam
Avenida das Américas, no. 3434, Salas 301 a 308, Barra da Tijuca, Rio de Janeiro, RJ, 22640-102, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Oficina 401, Carrera 14 N° 93B -45, Bogotá, Colombia
Av. Camino Real, 111 Torre B Oficina, 603 San Isidro, Lima, Peru
Castrol Hungária Kft, 30-34/E. Soroksári ùt, H-1095 Budapest, Hungary

Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Erkelenzer Straße 20, 41179 Mönchengladbach, Germany
East Tower 20F, Gate CIty Ohsaki, 1-11-2 Osaki, Shinagawa-ku, Tokyo, Japan
Technology Centre, Whitchurch Hill, Pangbourne, Reading, RG8 7QR, United Kingdom
V Parku 2294/2, 148 00 Praha 4, Czech Republic
5th Floor, 92-96 Izvor St, 5th District, Bucharest, Romania
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. Cuajimalpa C.P., 05349 México D.F.,
Mexico
BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
D-67/1, Block # 4, Scheme # 5, Clifton, Karachi, Pakistan
32/F LKG Tower, Ayala Avenue, Makati City, 6801, Philippines
Avenida Tamboré, 448, Barueri, Sao Paulo, Brazil
Rozˇnavská 24, 821 04 Bratislava 2, Slovakia
BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa
2a Konstiantynivskay Street, Kyiv, 04071, Ukraine
Barking Road, Willowvale, Harare, Zimbabwe
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Av. Eugenio Mendoza, San Felipe Edificio Centro Letonia, La Castellana, Caracas, 1060, Venezuela
Easton and Swamp Roads, Buckinham Township, Bucks County, Pennsylvania, United States
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Level 17, 717 Bourke Street, Docklands VIC, Australia
Timmerhellstsr. 28, 45478, Mülheim/Ruhr, Germany
240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada
240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada

240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada
240 - Fourth Avenue SW, Calgary AB T2P 4H4, Canada
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Watercare House, 73 Remuera Road, Newmarket, Auckland, 1050, New Zealand
1300 East Ninth Street, Cleveland, OH, 44114, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
112 SW 7th Street, Suite 3C, Topeka, Kansas, 66603, United States
Avenida Eliodoro Yañez N° 1572, Providencia , Santiago, Chile
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Francisco de Miranda, Edif Cavendes, Los Palos Grandes, Chacao, Caracas Miranda, 1060,
Venezuela
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

232

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14. Related undertakings of the group – continued

Box 8107, 10420, Stockholm, Sweden
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal

Fuel & Retail Aviation Sweden AB
FUELPLANE- Sociedade Abastecedora de Aeronaves,
Unipessoal, Lda
Gardena Holdings Inc.
Gasolin GmbH
Gasolinera Industrial S.L.
GOAM 1 C.I S. A .S
Grampian Aviation Fuelling Services Limited
Grangemouth Holdings Limited
Grangemouth Properties Limited
Guangdong Investments Limited
Highlands Ethanol, LLCa
Hydrogen Energy International Limited
IGI Resources, Inc.
International Card Centre Limited
Iraq Petroleum Company Limited
J & A Petrochemical Sdn. Bhd.
Jupiter Insurance Limited
Kabulonga Properties Limited
Ken-Chas Reserve Company
Kenilworth Oil Company Limitedi
Latin Energy Argentina S.A.
Lebanese Aviation Technical Services S.A.L.
Lubricants UK Limited
Mardi Gras Endymion Oil Pipeline Company, LLCa
Mardi Gras Transportation System Inc.
Markoil, S.A. Unipersonal
Masana Petroleum Solutions (Pty) Ltd (37.88%)
Mayaro Initiative for Private Enterprise Development (70.00%)a 5-5A Queen’s Park West, Port-of-Spain, Trinidad and Tobago
Mehoopany Holdings LLCa
Mes Tecnologia en Servicios y Energia, S.A. DE C.V.

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Wittener Straße 45, 44789 Bochum, Germany
Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain
Calle 80 No.11-42, Bogota, 110111, Colombia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
12550 W. Explorer Dr., Suite 100, Boise, Idaho, 83713, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Symphony House, Pusat Dagangan Dana 1, Jalan PJU 1A/46, 47301 Petaling Jaya, Selangor, Malaysia
The Albany, South Esplanade, St Peter Port, GY1 4NF, Guernsey
3rd floor Mukuba Pension House, Dedan Kimathi Road, Lusaka 10101, Zambia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Av. Cordoba 315 Piso 8, Buenos Aires, 1054, Argentina
P.O. Box - 11 -5814 c/o Coral Oil Building, 583 Avenue de Gaulle, Raoucheh, Beirut, Lebanon
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain
BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa

Minza Pty. Ltd.
Mountain City Remediation, LLCa
No. 1 Riverside Quay Proprietary Limited
Nordic Lubricants A/S
Nordic Lubricants AB
Nordic Lubricants Oy
North America Funding Company
Oelwerke Julius Schindler GmbH
OMD87, Inc.
Omega Oil Company
Orion Delaware Mountain Wind Farm LPa
Orion Energy Holdings, LLCa
Orion Energy L.L.C.a
Orion Post Land Investments, LLCa
Pacroy (Thailand) Co., Ltd. (39.00%)
Pan American Petroleum Company of California
Pan American Petroleum Corporation
Peaks America Inc.
Pearl River Delta Investments Limited
Phoenix Petroleum Services, Limited Liability Company
Products Cogeneration Company
Produits Métallurgie Doittau SA - PROMEDO

ProGas Limited
ProGas U.S.A., Inc.
Prospect International, C.A.
PT BP Petrochemicals Indonesia
PT Castrol Indonesia (68.30%)

PT Jasatama Petroindoc

Reading Investment (Nominee) Limited
Reax Industria e Comercio Ltda.
Remediation Management Services Company
Richfield Oil Corporation
Rolling Thunder I Power Partners, LLCa
Ropemaker Deansgate Limited
Ropemaker Properties Limited
Ruehl Gesellschaft m.b.H. & Co KG.g
Ruhr Oel GmbH (ROG)
Rural Fuel Limited
Saltend Chemicals Park Limited
Saturn Insurance Inc.
Setra Lubricants Kazakhstan LLPg
Setra Lubricantsa
Sherbino I Holdings LLCa
Sherbino II Wind Farm LLCa
Sherbino Mesa I Land Investments LLCa
Shine Top International Investment Limited
Silver Star I Power Partners, LLCa
Sociedade de Promocao Imobiliaria Quinta do Loureiro, SA
Société de Gestion de Dépots d’Hydrocarbures - GDHa

SOFAST Limited (62.77%)t
Southeast Texas Biofuels LLCa
Southern Ridge Pipeline Holding Company
Southern Ridge Pipeline LP LLCa
Sp/f Decision3 (GreenSteam) Companyu
SRHP (99.99%)a

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Av. Santa Fe No. 505 Piso 10, Col. Cruz Manca Santa Fe, Deleg. Cuajimalpa C.P., 05349 México D.F.,
Mexico
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Arne Jacobsens Allé 7, 5th Floor, 2300, Copenhagen, Denmark
Box 49104, S-100 28 Stockholm, Sweden
Teknobulevardi 3-5, 01530 Vantaa, Finland
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Überseeallee 1, 20457, Hamburg, Germany
111 Eighth Avenue, New York, New York, 10011, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand
818 West Seventh Street, 2nd Floor, Los Angeles, CA, 90017, United States
311 S. Division St., Carson City NV 89703, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Baghdad International Airport, Al-Burhan Commercial Complex , First floor, Baghdad, Iraq
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise,
France
240–Fourth Avenue SW, Calgary AB T2P 4H4, Canada
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Av. Eugenio Mendoza, San Felipe Edificio Centro Letonia, La Castellana, Caracas, 1060, Venezuela
20th Floor Summitmas II Jl., Jend. Sudirman Kav. 61 - 62, Jakarta, Selatan, Indonesia
Perkantoran Hijau Arkadia, Tower B, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta 12520,
Indonesia
Perkantoran Hijau Arkadia, Tower E, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta 12520,
Indonesia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Estrada São Lourenço, 751, part, Duque de Caxias, Rio Janeiro, Brazil
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Straße 6, Objekt 17, Industriezentrum NÖ-Süd, 2355 Wr. Neudorf, Austria
Johannastraße 2-8, 45899 Gelsenkirchen-Horst, Germany
AR Short & Co, Level 8, FMG Building, 55 The Square, Palmerston North, New Zealand
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
400 Cornerstone Drive, Suite 240, Williston VT 05495, United States
98 Panfilov Street, office 809, Almaty, 05000, Kazakhstan
2 Paveletskaya sq, Building1, 115054 Moscow, Russian Federation
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Unit 807, Tower B, Manulife Financial Centre, 223 Wai Yip Street, Kwun Tong, Kowloon, Hong Kong
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise,
France
23rd Fl. Rajanakarn Bldg, 3 South Sathon Road, Yannawa Sathon, Bangkok 10120, Thailand
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Krosslíð 11, FO-100 Tórshavn , Faroe Islands
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise, France

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

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Standard Oil Company, Inc.
Taradadis Pty. Ltd.
TEA Comercio E Participacoes Ltda.
Telcom General Corporatione
Terre de Grace Partnership (75.00%)g
The Anaconda Company
The BP Share Plans Trustees Limitedi
The Burmah Oil Company (Pakistan Trading) Limited
The Shorebank Corporation
The Standard Oil Company
TJKK
TOC-Rocky Mountains Inc.
Toledo Refinery Holding Company LLCa
Trinity Hills Wind Farm LLCa
Union Texas International Corporation
UT Petroleum Services, LLCa
Vastar Energy, Inc.
Vastar Gas Marketing, Inc.
Vastar Holdings, Inc.
Vastar Pipeline, LLCa
Vastar Power Marketing, Inc.
Verano Collateral Holdings LLCa
Viceroy Investments Limited
Warrenville Development Limited Partnershipa
Water Way Trading and Petroleum Services LLC (90.00%)
Welchem, Inc.
West Kimberley Fuels Pty Ltd
Westlake Houston Development, LLCa
Whiting Clean Energy, Inc.
Windpark Energy Nederland B.V.
Wiriagar Overseas Ltd

251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Avenida Itaóca, 2400, sala 108, Inhauma, Rio de Janeiro, Brazil
818 West Seventh Street, 2nd Floor, Los Angeles, CA, 90017, United States
1100, 635 - 8th Avenue SW, Calgary AB T2P 3M3, Canada
814 Thayer Avenue, Bismarck, ND, 58501-4018, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
7054 S. Jeffery Blvd., Chicago IL 60649, United States
1300 East Ninth Street, Cleveland, OH, 44114, United States
Roppongi Hills Mori Tower, 10-1 Roppongi 6-chome, Minato-ku, Tokyo106-6115, Japan
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
33 North LaSalle Street, Chicago, Illinois 60602, United States
Hay Al Wihda, Q904, Alley 68, H32, Korodha, Baghdad, Iraq
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Rivium Boulevard 301, 2909LK Capelle aan den IJssel, Netherlands
Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

234

BP Annual Report and Form 20-F 2016

14. Related undertakings of the group – continued

Level 3, Unit 3, 22 Albert Road, South Melbourne VIC 3205, Australia

Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago

Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago
Maracaibo Drive, Point Lisas Industrial Estate, Point Lisas, Trinidad and Tobago
1 Tanker Street, Lytton QLD, Australia

7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
2-2 Sangnam-ri, Chungryang-myun, Ulju-gun, Ulsan 689-863, Republic of Korea
Degirmen yolu cad. No:28, Asia OfisPark K:3|cerenkoy-Atasehir, Istanbul, 34752, Turkey
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
Princes Court, Cor. Pembroke & Keate Street, Port-of-Spain, Trinidad and Tobago

Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile
Via Lazio 20/C, 00187 Roma, Italy
Avenida Ricardo Rivera Navarrete n.501 / room 1602, Lima, Peru
Av. Anita Garibaldi, n.252, 2o floor, Ala Sul, Federação, Salvador, Bahia, 40210-750, Brazil
Oude Vijfhuizerweg 6, 1118LV Luchthaven, Schiphol, Netherlands
Trabrennstraße 6-8 3, A-1020, Wien, Austria
2 Market Street, Sydney NSW, Australia
Oksenoyveien 10, 1366 Lysaker, Norway
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
9360 Glacier Highway, Suite 202, Juneau AK 99801, United States
Yakuplu Mahallesi Genc, Osman Caddesi, No.7 Beylikdüzü, Istanbul, Turkey
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
c/o Mannheimer Swartling Advokatbyra Norrmalmstrog, 4 Box 1711, 111 87 Stockholm, Sweden
Riyadh Airport Road, Business Gate, Building C2, 2nd Floor. , Saudi Arabia

Related undertakings other than subsidiaries
Brucknerstraße 4, 1041 Wien, Austria
ABG Autobahn-Betriebe GmbH (32.58%)a
Abu Dhabi Marine Areas Limited (33.33%)b
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Abu Dhabi Petroleum Company Limited (23.75%)v
Rooms 522-524, 3rd Floor, Salisbury House, London Wall, London, EC2M 5QQ, United Kingdom
Advanced Biocatalytics Corporation (24.20%)w
18010 Skypark Circle, #130, Irvine CA 92614, United States
AGES International GmbH & Co. KG, Langenfeld (24.70%)g
Berghausener Straße 96, 40764 Langenfeld, Germany
AGES Maut System GmbH & Co. KG, Langenfeld (24.70%)g Berghausener Straße 96, 40764 Langenfeld, Germany
Air BP Copec S.A. (51.00%)
Air BP Italia Spa (50.00%)
Air BP PBF del Peru S.A.C. (50.00%)
Air BP Petrobahia Ltda. (50.00%)
Aircraft Fuel Supply B.V. (28.57%)
Aircraft Refuelling Company GmbH (33.33%)a
Airport Fuel Services Pty. Limited (20.00%)
Aker BP ASA (30.00%)
Alaska Tanker Company, LLC (25.00%)a
Alyeska Pipeline Service Company (48.44%)
Ambarli Depolama Hizmetleri Limited Sirketi (50.00%)
Ammenn GmbH (75.00%)
Amoco Bolivia Oil and Gas Aktiebolag (60.00%)
Arabian Production And Marketing Lubricants Company
(50.00%)
ARCO Solar Nigeria Ltd. (40.00%)
Asian Acetyls Co., Ltd (34.00%)
ATAS Anadolu Tasfiyehanesi Anonim Sirketi (68.00%)
Atlantic 1 Holdings LLC (34.00%)a
Atlantic 2/3 Holdings LLC (42.50%)a
Atlantic 4 Holdings LLC (37.78%)a
Atlantic LNG 2/3 Company of Trinidad and Tobago Unlimited
(42.50%)
Atlantic LNG 4 Company of Trinidad and Tobago Unlimited
(37.78%)
Atlantic LNG Company of Trinidad and Tobago (34.00%)
Atlas Methanol Company Unlimited (36.90%)
Australasian Lubricants Manufacturing Company Pty Ltd
(50.00%)b
Australian Terminal Operations Management Pty Ltd
(50.00%)
Auwahi Holdings, LLC (50.00%)a
Auwahi Wind Energy LLC (50.00%)a
Aviation Fuel Services Limited (25.00%)
Azerbaijan Gas Supply Company Limited (23.06%)b
Azerbaijan International Operating Company (40.50%)x
Baplor S.A. (60.00%)
Barranca Sur Minera S.A. (60.00%)
Bayernoil Raffineriegesellschaft mbH (35.00%)
Beer GmbH & Co. Mineralol-Vertriebs-KG (50.00%)g
Beer GmbH (50.00%)
BGFH Betankungs-Gesellschaft Frankfurt-Hahn GbR (50.00%)g Sportallee 6, 22335 Hamburg, Germany
Billund Refuelling I/S (50.00%)
Blendcor (Pty) Limited (37.50%)s
BP AOC Pumpstation Maatschap (50.00%)g
BP Dhofar LLC (49.00%)
BP Esso AOC Maatschap (22.80%)g
BP Esso Pipeline Maatschap (50.00%)g
BP Guangzhou Development Oil Product Co., Ltd (40.00%)
BP India Limited (51.00%)
BP PetroChina Petroleum Co., Ltd (49.00%)
BP Petronas Acetyls Sdn. Bhd. (70.00%)
BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%)
BP Sinopec Marine Fuels Pte. Ltd. (50.00%)
BP YPC Acetyls Company (Nanjing) Limited (50.00%)
BP-Husky Refining LLC (50.00%)a
BP-Japan Oil Development Company Limited (50.00%)b
BTC International Investment Co. (30.10%)y
Butamax™ Advanced Biofuels LLC (50.00%)a
Caesar Oil Pipeline Company, LLC (56.00%)a
Cairns Airport Refuelling Service Pty Ltd (25.00%)
Cantera K-3 Limited Partnership (39.00%)g
Castrol Cuba S.A. (50.00%)
Castrol DongFeng Lubricant Co., Ltd (50.00%)
Cedar Creek II Holdings LLC (50.00%)a
Cedar Creek II, LLC (50.00%)a
Cekisan Depolama Hizmetleri Limited Sirketi (35.00%)
Central African Petroleum Refineries (Pvt) Ltd (20.75%)
Chicap Pipe Line Company (56.17%)a
China American Petrochemical Company, Ltd. (CAPCO)
(61.36%)
China Aviation Oil (Singapore) Corporation Ltd (20.03%)
Cleopatra Gas Gathering Company, LLC (54.00%)a
Coastal Oil Logistics Limited (25.00%)
Combined Refuelling Service VOF (25.00%)g
Compania de Inversiones El Condor Limitada (99.00%)
Concessionaria Stalvedro SA (50.00%)
CSG Convenience Service GmbH (24.80%)
Cypress Pipeline Company, L.L.C. (50.00%)a
Danish Refuelling Service I/S (33.33%)g
Danish Tankage Services I/S (50.00%)g
The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

GA Centervej 1, DK-7190, Billund, Denmark
135 Honshu Road, Islandview, Durban, 4052, South Africa
Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands
P.O.Box 20302/211, 20302, Oman
Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands
Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands
No.13 Longxue Road, Longxue Island, Nansha District, Guangzhou, Guangdong, 511450, China
Technopolis Knowledge Park, Mahakali Caves Road, Andheri (East), Mumbai 400 093, India
Room A 17th Floor, No.22 Gangkou Road, Jiangmen, Guangdong Province, China
Symphony House, Pusat Dagangan Dana 1, Jalan PJU 1A/46, 47301 Petaling Jaya, Selangor, Malaysia
12 Hua Zhe Plaza, 1 Hua Zhe Square, Hang Zhou City, Zhe Jiang Province, China
112 Robinson Road, #05-01, Robinson 112, 068902, Singapore
9# Huo Ju Road, Liu He District, Nanjing, Jiangsu Province, China
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1 Wellheads Avenue, Dyce, Aberdeen, AB21 7PB, United Kingdom
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2 Market Street, Sydney NSW, Australia
6400 Shafer Ct., Suite 400, Rosemont IL 60018-4927, United States
Calle 6 No 319, esq 5ta. Ave., Miramar, Playa, La Habana, Cuba
Room 1404-1405, Donghe Centre Tower B, 3 Sanjiao Hu Road, Wuhan, Hubei Province, China
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
1560 Broadway, Suite 2090, Denver, Colorado, 80202, United States
Yakuplu Ambarli Mevkii, 9 Ada2-3-6-7 Parsel, Büyükçekmece, Istanbul, Turkey
Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
9th Floor No. 392 Ruei Kuang Road, Neihu 11492, Taipei, Taiwan

2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
National Registered Agents, Inc., 160 Greentree Dr., Dover, Delaware, 19904, United States
Calshot Way Central Area, Heathrow Airport, Hounslow, Middlesex, TW6 1PY, United Kingdom
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands
190 Elgin Avenue, George Town, Grand Cayman, KY1-9005, Cayman Islands
Colonia 810, Oficina 403, Montevideo, Uruguay
Calle 14, No 781, Piso 2, Oficina 3, Ciudad de La Plata, Provincia de Buenos Aires, Argentina
Postfach 10 08 58, 85008 Ingolstadt, Germany
Saganer Straße 31, 90475 Nürnberg, Germany
Saganer Straße 31, 90475 Nürnberg, Germany

8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
10th Floor, The Bayleys Building, Cnr Brandon St and Lambton Quay, Wellington, 6011, New Zealand
Anchoragelaan 4, 1118 LD, Schipol, Netherlands
Av. Andrés Bello 2711, Piso 24, Las Condes, Santiago, Chile
San Gottardo Sud, 6780, Airolo, Switzerland
Wittener Straße 45, 44789 Bochum, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Kastrup Lufthavn, 2770 Kastrup, Denmark
Kastrup Lufthavn, 2770 Kastrup, Denmark

BP Annual Report and Form 20-F 2016

235

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14. Related undertakings of the group – continued

Dinarel S.A. (24.00%)
Dusseldorf Fuelling Services GbR (33.00%)g
Dusseldorf Tank Services GbR (33.00%)g
East Tanka Petroleum Company “ETAPCO” (50.00%)
Ekma Oil Company “EKMA” (50.00%)
El Temsah Petroleum Company “PETROTEMSAH”
(25.00%)
EMDAD Aviation Fuel Storage FZCO (33.33%)
Emoil Storage Company FZCO (20.00%)
Endymion Oil Pipeline Company, LLC (75.00%)a
Energenomics LLC (50.00%)a
Energy Emerging Investments, LLC (60.00%)a
Entrepot petrolier de Chambery (32.00%)
Entrepôt Pétrolier de Puget sur Argens - EPPA (58.25%)

Erdol-Lagergesellschaft m.b.H. (23.00%)a
Eroil Mineraloel GmbH - Diehl (50.00%)
Esma Petroleum Company “ESMA” (50.00%)
Estonian Aviation Fuelling Services (49.00%)
Etzel-Kavernenbetriebsgesellschaft mbH & Co. KG
(33.00%)g
Etzel-Kavernenbetriebs-Verwaltungsgesellschaft mbH
(33.33%)
FFS Frankfurt Fuelling Services (GmbH & Co.) OHG
(33.00%)g
Fibil SA (50.00%)
Field Services Enterprise S.A. (60.00%)
Fip Verwaltungs GmbH (50.00%)
Flat Ridge 2 Wind Energy LLC (50.00%)a
Flat Ridge 2 Wind Holdings LLC (50.00%)a
Flughafen Hannover Pipeline Verwaltungsgesellschaft mbH
(50.00%)
Flughafen Hannover Pipelinegesellschaft mbH & Co. KG
(50.00%)g
Flytanking AS (50.00%)
Foreseer Ltd (25.00%)
Formosa BP Chemicals Corporation (50.00%)
Fowler I Holdings LLC (50.00%)a
Fowler II Holdings LLC (50.00%)a
Fowler Ridge II Wind Farm LLC (50.00%)a
Fowler Ridge Wind Farm LLC (50.00%)a
Fuelling Aviation Service—FAS (50.00%)a
Fundación para la Eficiencia Energética de la Comunidad
Valenciana (33.33%)a
Gardermeon Fuelling Services AS (33.33%)
Gemalsur S.A. (60.00%)
Georg Reitberger Mineralole GmbH & Co. KG (50.00%)g
Georg Reitberger Mineralöle Verwaltungs GmbH (50.00%)
Georgian Pipeline Company (40.50%)x
Gezamenlijke Tankdienst Schiphol B.V. (50.00%)
GISSCO S.A. (50.00%)
Goshen Phase II LLC (50.00%)a
Gothenburgh Fuelling Company AB (GFC) (33.33%)
Gravcap, Inc. (25.00%)
Groupement Pétrolier de Saint Pierre des Corps - GPSPC
(20.00%)a
Groupement Pétrolier de Strasbourg (33.33%)a
Groupement pour l’Avitaillement de Lyon Saint-Exupéry -
GALYS (39.93%)a
Guangdong Dapeng LNG Company Limited (30.00%)
Gulf Of Suez Petroleum Company “GUPCO” (50.00%)
GVÖ Gebinde-Verwertungsgesellschaft der
Mineralölwirtschaft mbH (21.00%)
H & G Contracting Services Limited (33.50%)
Hamburg Tank Service (HTS) GbR (33.00%)g
Heinrich Fip GmbH & Co. KG (50.00%)g
Heliex Power Limited (32.40%)w
HFS Hamburg Fuelling Services GbR (25.00%)g
Hiergeist Heizolhandel GmbH & Co. KG (50.00%)g
Hiergeist Verwaltung GmbH (50.00%)
Hokchi Energy S.A. de C.V. (60.00%)
Hokchi Iberica S.L. (60.00%)

Hydrogen Energy International LLC (50.00%)a
In Salah Gas Ltd (25.50%)s
In Salah Gas Services Ltd (25.50%)s
India Gas Solutions Private Limited (50.00%)
Jamaica Aircraft Refuelling Services Limited (51.00%)b
Kingston Research Limited (50.00%)
Klaus Köhn GmbH (50.00%)
Köhn & Plambeck GmbH & Co. KG (50.00%)g
Kosmos BP Senegal Limited (49.99%)
Kurt Ammenn GmbH & Co. KG (50.00%)g
LFS Langenhagen Fuelling Services GbR (50.00%)g
Limited Liability Company TYNGD (20.00%)a
Lotos—Air BP Polska Spółka z ograniczona˛
odpowiedzialnos´ cia˛ (50.00%)
LOTTE BP Chemical Co., Ltd (51.00%)
Maasvlakte Europoort Pipeline Maatschap (50.00%)g

La Cumparsita 1373, piso 4°, Montevideo, Uruguay
Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt

P.O.Box 261781, Dubai, United Arab Emirates
Plot No. B003R04, Box No. 9400, Dubai, United Arab Emirates
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
562 Avenue du Parc de l’Ile, 92000, Nanterre, France
Immeuble Le Cervier, 12 Avenue des Béguines, Cergy Saint Christophe, 95866, Cergy Pontoise,
France
Radlpaßstraße 6, 8502 Lannach, Austria
Schillerstraße 10, 66482 Zweibrücken, Germany
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
Lennujaama tee 2, TallinnEE0011, Estonia
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany

Bertrand-Russell-Straße 3, 22761 Hamburg, Germany

Sportallee 6, 22335 Hamburg, Germany

Autostradale Coldrerio-Est, 6877, Coldrerio, Switzerland
Av. Leandro N. Alem 1180, piso 11, Buenos Aires, Argentina
Rheinstraße 36, 49090 Osnabrück, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Überseeallee 1, 20457, Hamburg, Germany

Überseeallee 1, 20457, Hamburg, Germany

Postboks 36, Stjordal, NO-7501, Norway
121A Thoday Street, Cambridge, Cambridgeshire, CB1 3AT, United Kingdom
No. 1-1Formosa Industrial Comples, Mailiao, Yunlin Hsien, Taiwan
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
3 Rue des Vignes, Aéroport Charles de Gaulle, 93290, Tremblay en France, France
Calle Lituania nº 10, Castellón de la Plana, Spain

Postboks 133, Gardermoen, NO-2061, Norway
Colonia 810, Oficina 403, Montevideo, Uruguay
Bahnhofstraße 25, 86551 Aichach, Germany
Bahnhofstraße 25, 86551 Aichach, Germany
190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands
Anchoragelaan 6, 1118 LD Schiphol, Netherlands
2,Vouliagmenis Ave & Papaflessa, 16777 Elliniko, Athens, Attika, Greece
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Box 2154, 438 14, Landvetter, Sweden
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
150 Avenue Yves Farge, 37700, Saint Pierre des Corps, France

562 Avenue du Parc de l’Ile, 92000, Nanterre, France
Aéroport de Lyon Saint Exupéry, 69124, Colombier-Saugnieu, France

10-11/FTime Finance Center, No.4001 Shennan Dadao, Shenzhen, Guangdong Province, China
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
Steindamm 55, 20099 Hamburg, Germany

Third Floor, One London Square, Cross Lanes, Guildford, GU1 1UN , United Kingdom
Sportallee 6, 22335 Hamburg, Germany
Rheinstraße 36, 49090 Osnabrück, Germany
Kelvin Building, Bramah Avenue, East Kilbride, Glasgow, Scotland, G75 0RD, United Kingdom
Sportallee 6, 22335 Hamburg, Germany
Grubenweg 4, 83666 Waakirchen-Marienstein, Germany
Grubenweg 4, 83666 Waakirchen-Marienstein, Germany
Torre A, Calzada Legaria 549, Colonia 10 de Abril, Ciudad de Mexico, C. P. 11250, Mexico
Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid,
Spain
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
22 Grenville Street, St Helier, JE4 8PX, Jersey
22 Grenville Street, St Helier, JE4 8PX, Jersey
2nd North Avenue, Bandra - Kurla Complex, Bandra (East), Mumbai 400 051, Maharashtra, India
PCJ Building36 Trafalgar Road, Kingston 10, Jamaica
C/O Banks Cooper Associates, 21 Marina Court, Hull, HU1 1TJ, United Kingdom
An der Braker Bahn 22, 26122 Oldenburg, Germany
An der Braker Bahn 22, 26122 Oldenburg, Germany
Wilmington Trust SP Services (London) Limited, Kings Arms Yard, London EC2R 7AF, United Kingdom
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
Sportallee 6, 22335 Hamburg, Germany
Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation
ul. Elbla˛ ska nr 135, 80-718 Gdan´ sk, 80-718, Gdan´ sk, Województwo Pomorskie, Poland

2-2 Sangnam-ri, Chungryang-myun, Ulju-gun, Ulsan 689-863, Republic of Korea
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

236

BP Annual Report and Form 20-F 2016

Moezelweg 101, 3198 LS Europoort, Rotterdam, Netherlands
Naz City, Building J, Suite 10 Erbil, Iraq
Box 22, SE 230 32 Malmö-Sturup, Sweden
Bircham Dyson Bell, 50 Broadway, London, SW1H 0BL, United Kingdom

Francisco Behr 20, Barrio Pueyrredon, Comodoro Rivadavia, Provincia del Chubut, Argentina
5615 Corporate Blvd., Suite 400B, Baton Rouge LA 70808, United States
20 Rue Contades, 67300, Schiltigheim, France
700 Bond Street, Te Awamutu, New Zealand
5 El Mokhayam El Daiem St, 6th Sector, Nasr City, Egypt
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
6th Flr City Tower, 2 - Sheikh Zayed Road, PO Box 1699, Dubai, United Arab Emirates
900 E. Benson Boulevard, Anchorage, Alaska, 99508, United States
Kronestraße 22-23, 29221 Celle, Germany
Spaldingstraße 64, 20097 Hamburg, Germany
Spaldingstraße 64, 20097 Hamburg, Germany
Butaanweg 215, NL-3196 KC Vondelingenplaat, Rotterdam, 3045, Havennummer, Netherlands

14. Related undertakings of the group – continued

Maatschap Europoort Terminal (50.00%)g
Mach Monument Aviation Fuelling Co. Ltd. (70.00%)
Malmo Fuelling Services AB (33.33%)
Manchester Airport Storage and Hydrant Company Limited
(25.00%)
Manpetrol S.A. (60.00%)
Mars Oil Pipeline Company (28.50%)g
MATELUB S.A.R.L. (Baldersheim/Frankreich) (80.00%)
McFall Fuel Limited (30.07%)
Mediteranean Gas Co. “MEDGAS” (25.00%)
Mehoopany Wind Energy LLC (50.00%)a
Mehoopany Wind Holdings LLC (50.00%)a
Middle East Lubricants Company LLC (40.00%)
Milne Point Pipeline, LLC (50.00%)a
Mineralol-Handels-Gesellschaft mbH, Celle (50.00%)
Mobene GmbH & Co. KG (50.00%)g
Mobene Verwaltungs-GmbH (50.00%)
N.V. Rotterdam-Rijn-Pijpleiding Maatschappij (RRP)
(44.44%)
Natural Gas Vehicles Company “NGVC” (40.00%)
New Zealand Oil Services Limited (50.00%)
NFX Combustíveis Marítimos Ltda. (50.00%)
Nigermed Petroleum S.A. (50.00%)
Nord-West Oelleitung GmbH (59.33%)
North Ghara Petroleum Company (NOGHCO) (30.00%)
North October Petroleum Company “NOPCO” (50.00%)
Oberrheinische Mineralolwerke GmbH (33.00%)
Ocwen Energy Pty Ltd (49.50%)
Oleoductos Canarios, S.A. (20.00%)
OptoAtmospherics Inc (27.20%)w
Oslo Lufthaven Tankanlegg AS (33.33%)
PAE E & P Bolivia Limited (60.00%)
PAE Oil & Gas Bolivia Ltda. (60.00%)
Pan American Energy Chile Limitada (60.00%)
Pan American Energy do Brasil Ltda. (60.00%)a
Pan American Energy Holdings Ltd. (60.00%)
Pan American Energy Iberica S.L. (60.00%)

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85 El Nasr Road, Cairo, Cairo, Egypt
Level 3, 139 The Terrace, Wellington, 6011, New Zealand
Avenida Atlântica, no. 1.130, 2nd floor (part), Copacabana, Rio de Janeiro, RJ, 22021-000, Brazil
53rd East Street, Marbella, Swiss Bank Building, 2nd Floor, City of Panama, Republic of Panama
Zum Ölhafen 207, 26384 Wilhelmshaven, Germany
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
DEA-Scholven-Straße, 76187 Karlsruhe, Germany
GTH Accounting Group Pty Ltd ‘2’, 1A Kitchener Street, Toowoomba QLD 4350, Australia
C/ Explanada Tomas Quevedo S/N, 35008 Puerto De La Luz, Las Palmas De G.C, Spain
3500 DuPont Highway, Dover, County of Kent DE 19901, United States
Postboks 134, Gardermoen, NO-2061, Norway
Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas
Cuarto anillo, Avda. Ovidio Barbery N° 4200,Equipetrol Norte, Santa Cruz de la Sierra, Bolivia
Nueva de Lyon Nº 145, piso 12, oficina 1203, Edificio Costa, Santiago de Chile, Chile
Rua Manoel da Nóbrega n°1280, 10° andar, Sao Paulo, Sao Paulo, 04001-902, Brazil
Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands
Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid,
Spain
Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Colonia 810, Oficina 403, Montevideo, Uruguay
O´Higgins N° 194, Rio Grande, Argentina
O´Higgins N° 194, Rio Grande, Argentina
Kronestraße 22-23, 29221 Celle, Germany
P O Box 6369, Jeddah21442, Saudi Arabia
6th Floor (c/o Q8 Aviation), Dukes Court, Duke Street, Woking, GU215BH, United Kingdom
Route de Pré-Bois 2, 1214, Vernier, Switzerland
70/72 Road 200, Maadi, Cairo, Egypt
Villa Tulip 27, An Phu, District 2, Ho Chi Minh City, Vietnam
9360 Glacier Highway, Suite 202, Juneau AK 99801, United States

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Bakrie Tower 17th Floor, Rasuna Epicentrum Complex Jl. H.R Rasuna Said, Jakarta, 12940, Indonesia
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
24 Cours Michelet, 92800, Puteaux, France

Pan American Energy Investments Ltd. (60.00%)
Pan American Energy LLC (60.00%)a
Pan American Energy Uruguay S.A. (60.00%)
Pan American Fueguina S.A. (60.00%)
Pan American Sur S.A. (60.00%)
Paul Harling Mineralole GmbH & Co. KG (50.00%)g
Peninsular Aviation Services Company Limited (25.00%)
Pentland Aviation Fuelling Services Limited (25.00%)b
Petrostock SA (50.00%)
Pharaonic Petroleum Company “PhPC” (25.00%)
Phu My 3 BOT Power Company Limited (33.33%)g
Prince William Sound Oil Spill Response Corporation
(25.00%)
Proteus Oil Pipeline Company, LLC (75.00%)a
PT Petro Storindo Energi (30.00%)
PTE Pipeline LLC (32.00%)a
Raffinerie de Strasbourg (33.33%)
Rahamat Petroleum Company (PETRORAHAMAT) (50.00%) 70/72 Road 200, Maadi, Cairo, Egypt
Hörhof 1, 95473 Creußen, Germany
Raimund Mineraloel GmbH (50.00%)
26 Kifissias Ave. and 2 Paradissou st., 15125 Maroussi, Athens, Greece
RAPISA (62.51%)
Nideracher 1, 8867, Niederurnen, Switzerland
Raststaette Glarnerland AG, Niederurnen (20.00%)
Albert Alloo & Sons, 67 Princes Street, Dunedin, New Zealand
RD Petroleum Limited (49.00%)
Resolution Partners LLP (68.00%)g
1675 Broadway, Denver CO 80202, United States
Godorfer Hauptstraße 186, 50997 Köln, Germany
Rhein-Main-Rohrleitungstransportgesellschaft mbH
(35.00%)
Rio Grande Pipeline Company (30.00%)g
RocketRoute Limited (29.40%)w
Romanian Fuelling Services S.R.L. (50.00%)
Rosneft Oil Company (19.75%)
Routex B.V. (25.00%)
Rudeis Oil Company “RUDOCO” (50.00%)
Rundel Mineraloelvertrieb GmbH (50.00%)
S&JD Robertson North Air Limited (49.00%)
SABA- Sociedade Abastecedora de Aeronaves, Lda
(25.00%)
SAFCO SA (33.33%)
Salzburg Fuelling GmbH (33.00%)a
Saraco SA (20.00%)
SBB Dortmund GmbH (25.00%)
Servicios Logísticos de Combustibles de Aviación, S.L
(50.00%)
Shanghai SECCO Petrochemical Company Limited (50.00%) No. 557 South Yinhe Road, Shanghai Chemical Industry Park, Caojing, Shanghai, China
Sharjah Aviation Services Co. LLC (49.00%)s
Sharjah Pipeline Company LLC (49.00%)
Shell and BP South African Petroleum Refineries (Pty) Ltd
(37.50%)b
Shell Mex and B.P. Limited (40.00%)s
Shenzhen Cheng Yuan Aviation Oil Company Limited
(25.00%)

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Barttelot Court, Barttelot Road, Horsham, West Sussex, RG12 1DQ, United Kingdom
59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania
26/1 Sofiyskaya Embankment, 115035, Moscow, Russian Federation
Strawinskylaan 1725, 1077XX Amsterdam, Netherlands
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
Am Güterbahnhof 4, 78224 Singen, Germany
1 Wellheads Avenue, Dyce, Aberdeen, AB217PB, United Kingdom
Grupo Operacional de Combustiveis do Aeroporto de Lisboa, Edificio 19, 1.º Sala Saba, Lisboa,
Portugal
International airport “El. Venizelos”, Athens, Greece
Innsbrucker Bundesstraße 95, 5020 Salzburg, Austria
Route de Pré-Bois 17, 1216, Cointrin, Switzerland
Westfalendamm 166, 44141 Dortmund, Germany
Vía de los Poblados 1, Madrid, Spain

P O Box- 97, Sharjah, United Arab Emirates
Sharjah 42244, Sharjah, UAE, Sharjah, United Arab Emirates
1 Refinery Road, Prospecton, 4110, South Africa

Shell Centre, London, SE17NA, United Kingdom
Fu Yong Town, Bao An county, ShenZhen Airport, Guangdong Province, China

The parent company financial statements of BP p.l.c. on pages 215-238 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 2016

237

14. Related undertakings of the group – continued

5 Clementi Loop, Singapore 129816, Singapore
Causeway House, 1 Dane Street, Bishop’s Stortford, Hertfordshire, CM23 3BT, United Kingdom
Holstenhofweg 47, 22043 Hamburg, Germany

Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
LOB 16, Suite #309, Jebel Ali Free Zone, Dubai, PO BOX 262794, United Arab Emirates
Shell International Petroleum, Co Ltd, Shell Centre, 8 York Road, London, SE1 7NA, United Kingdom
1 Place Gustave Eiffel, 94150, Rungis, France

P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman
Islands
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands

Baiyun Internation Airport, Guangzhou, China

27 Route du Bassin Numéro 6, 92230, Gennevilliers, France

Room 316 Excellence Mansion, No.98 Fuhua 1Rd, Futian District, Shenzhen, China

Shenzhen Dapeng LNG Marketing Company Limited
(30.00%)
Sherbino I Wind Farm LLC (50.00%)a
SKA ENERGY HOLDINGS LIMITED (50.00%)
SM Realisations Limited (In Liquidation) (40.00%)
Société d’Avitaillement et de Stockage de Carburants
Aviation “SASCA” (40.00%)a
Société de Gestion de Produits Pétroliers - SOGEPP
(37.00%)
South Caucasus Pipeline Company Limited (28.83%)s
South Caucasus Pipeline Holding Company Limited
(28.83%)
South Caucasus Pipeline Option Gas Company Limited
(28.83%)
South China Bluesky Aviation Oil Company Limited
(24.50%)
ST-Airport Services Pte Ltd (33.00%)
Stansted Intoplane Company Limited (20.00%)
STDG Strassentransport Dispositions Gesellschaft mbH
(50.00%)
Stockholm Fuelling Services Aktiebolag (25.00%)
Box 7, 190 45 Arlanda, Sweden
Stonewall Resources Ltd. (60.00%)
Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands
Sunrise Oil Sands Partnership (50.00%)g
c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada
Tankanlage AG Mellingen (33.33%)
Birmenstorferstrasse 2, 5507, Mellingen, Switzerland
TAR - Tankanlage Ruemlang AG (27.32%)
Zwüscheteich, 8153, Rümlang, Switzerland
TAU Tanklager Auhafen AG (50.00%)
Auhafenstrasse 10a, 4132, Muttenz, Switzerland
Team Terminal B.V. (22.80%)
Rijndwarsweg 3, Havennr 5719, 3198LK Europoort Rotterdam, Netherlands
Tecklenburg GmbH & Co. Energiebedarf KG (50.00%)g
Wesermünder Straße 1, 27729 Hambergen, Germany
Tecklenburg GmbH (50.00%)
Wesermünder Straße 1, 27729 Hambergen, Germany
Terminales Canarios, S.L. (50.00%)
Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain
TFSS Turbo Fuel Services Sachsen GbR (20.00%)f
Sportallee 6, 22335 Hamburg, Germany
TGFH Tanklager-Gesellschaft Frankfurt-Hahn GbR (50.00%)g Sportallee 6, 22335 Hamburg, Germany
TGH Tankdienst-Gesellschaft Hamburg GbR (33.33%)g
Sportallee 6, 22335 Hamburg, Germany
TGHL Tanklager-Gesellschaft Hannover-Langenhagen GbR
Sportallee 6, 22335 Hamburg, Germany
(50.00%)g
TGK Tanklagergesellschaft Koln-Bonn (20.00%)g
The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)y
The Consolidated Petroleum Company Limited (50.00%)s
The Consolidated Petroleum Supply Company Limited
(50.00%)
The New Zealand Refining Company Limited (21.19%)
The Sullom Voe Association Limited (33.33%)s
TLM Tanklager Management GmbH (49.00%)a
TLS Tanklager Stuttgart GmbH (45.00%)
Torsina Oil Company “TORSINA” (37.50%)
TRaBP GbR (75.00%)g
Trafineo GmbH & Co. KG (75.00%)g
Trafineo Verwaltungs-GmbH (75.00%)
Transalpine Olleitung in Osterreich Gesellschaft m.b.H.
(20.00%)
TransTank GmbH (50.00%)
Unimar LLC (50.00%)a
United Gas Derivatives Company “UGDC” (33.33%)
United Kingdom Oil Pipelines Limited (33.50%)
Ursa Oil Pipeline Company LLC (22.69%)a
VIC CBM Limited (50.00%)
Virginia Indonesia Co. CBM Limited (50.00%)
Virginia Indonesia Co., LLC (50.00%)a
Virginia International Co., LLC
Walton-Gatwick Pipeline Company Limited (42.33%)
West London Pipeline and Storage Limited (30.50%)
West Morgan Petroleum Company (PETROMORGAN)
(50.00%)
Wiri Oil Services Limited (27.78%)
Xact Downhole Telemetry Inc (27.00%)w
Yangtze River Acetyls Co., Ltd (51.00%)

Am Stadthafen 60, 45881 Gelsenkirchen, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
55 Road 18, Maadi, Cairo, Egypt
5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom
Eni House, 10 Ebury Bridge Road, London, SW1W 8PZ, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom
5-7 Alexandra Road, Hemel Hempstead, Hertfordshire, HP2 5BS, United Kingdom
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt

Marsden Point, Ruakaka, New Zealand
Town Hall, Lerwick, Shetland, ZE10HB, United Kingdom
Am Tankhafen 4, 4020 Linz, Austria
Zum Ölhafen 49, 70327 Stuttgart, Germany
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
Huestraße 25, 44787, Bochum, Germany
Wittener Straße 56, Bochum, Germany
Wittener Straße 56, Bochum, Germany
Kienburg 11, 9971 Matrei in Osttirol, Austria

303 Parnell Rd, Parnell, Auckland, New Zealand
906 55th Avenue NE, Calgary AB, Canada
97 Weijiang Road (in the Petrochemical Park), Changshou District, Chongqing, China

Sportallee 6, 22335 Hamburg, Germany
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands
Shell Centre, London, SE17NA, United Kingdom
Shell Centre, London, SE17NA, United Kingdom

u B and D shares
v 23.75% ordinary shares and 23.75% A shares
w Preference shares
x Unlimited redeemable shares
y 1.89% A shares and 40.80% B shares

a Member interest
b A shares
c A and B shares
d Ordinary shares, B shares and preference shares
e Common stock and preference shares
f Ordinary shares and preference shares
g Partnership interest
h A, B and D shares
i Interest held directly by BP p.l.c.
j 99% held directly by BP p.l.c.
k 1% held directly by BP p.l.c.
l Ordinary shares, A and B shares
m0.008% held directly by BP p.l.c.
n Ordinary shares and cumulative redeemable preference shares
o 79.93% ordinary shares and 99.06% preference shares
p 93.59% ordinary shares and 81.01% preference shares
q Subsidiary in which the group does not hold a majority of the voting rights but exercises

control over it

r Ordinary shares and redeemable preference shares
s B shares
t 100% ordinary shares and 58.63% preference shares

The parent company financial statements of BP p.l.c. on pages 215-238 do not form part of BP’s Annual Report on Form 20-F as filed with the SEC.

238

BP Annual Report and Form 20-F 2016

Additional
disclosures

240 Selected financial information

242 Liquidity and capital resources

244 Upstream analysis by region

249 Downstream plant capacity

251 Oil and gas disclosures for the group

257 Environmental expenditure

257 Regulation of the group’s business

261 Legal proceedings

265 International trade sanctions

266 Material contracts

266 Property, plant and equipment

266 Related-party transactions

266 Corporate governance practices

267 Code of ethics

267 Controls and procedures

268 Principal accountants’ fees and services

268 Directors’ report information

269 Disclosures required under Listing Rule 9.8.4R

269 Cautionary statement

BP Annual Report and Form 20-F 2016

239

A
d
d
i
t
i
o
n
a

d
s
c
o
s
u
r
e
s

Selected financial information
This information, insofar as it relates to 2016, has been extracted or derived from the audited consolidated financial statements of the BP
group presented on page 114. 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

Profit (loss) before interest and taxation
Finance costs and net finance expense relating to pensions and other post-

retirement benefits

Taxation
Non-controlling interests

Profit (loss) for the yeara
Inventory holding (gains) losses*, before tax
Taxation charge (credit) on inventory holding gains and losses
RC profit (loss)* for the year
Net (favourable) unfavourable impact of non-operating items* and fair value

accounting effects*, before tax

Taxation charge (credit) on non-operating items and fair value accounting effects
Underlying RC profit* for the year
Earnings per shareb – cents

Profit (loss) for the yeara per ordinary share

Basic
Diluted

RC profit (loss) for the year per ordinary share*
Underlying RC profit for the year per ordinary share*

Dividends paid per share – cents
– pence

Additions to non-current assetsc
Capital expenditure on an accruals basis*b d

Organic capital expenditure*e
Inorganic capital expenditure*

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 dataf

Basic weighted average number of shares
Diluted weighted average number of shares

2016

2015

2014

2013

2012

$ million except per share amounts

183,008

222,894

353,568

379,136

375,765

(430)

(7,918)

6,412

31,769

19,769

(1,865)
2,467
(57)

115

(1,597)
483

(1,653)
3,171
(82)

(6,482)

1,889
(569)

(999)

(5,162)

(1,462)
(947)
(223)

3,780

6,210
(1,917)

8,073

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

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

23,451

11,017

290
(60)

594
(183)

23,681

11,428

6,746
(3,162)

2,585

15,067
(4,000)

8,234
(4,171)

(9,244)
(1,009)

6,110
(467)

5,905

12,136

13,428

17,071

0.61
0.60
(5.33)
13.79

40.00
29.418

21,204

18,440
939

19,379

(35.39)
(35.39)
(28.18)
32.22

40.00
26.383

20,080

18,748
710

19,458

20.55
20.42
43.90
66.00

39.00
23.850

26,492

22,892
601

23,493

123.87
123.12
125.08
70.92

36.50
23.399

36,916

24,600
12,007

36,607

263,316
96,843
5,284
95,286
51,666
26.8%

261,832
98,387
5,049
97,216
46,224
21.6%

284,305
112,642
5,023
111,441
45,977
16.7%

305,690
130,407
5,129
129,302
40,811
16.2%

57.89
57.50
60.05
89.70

33.00
20.852

29,268

23,950
1,097

25,047

300,466
119,752
5,261
118,546
38,767
18.7%

Share million

18,745
18,855

18,324
18,324

18,385
18,497

18,931
19,046

19,028
19,158

a Profit attributable to BP shareholders.
b A reconciliation to GAAP information is provided on page 285.
c Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures*; and investments in associates*.
d The definitions of capital expenditure on an accruals basis and inorganic capital expenditure have been revised to exclude asset exchanges as they are non-cash transactions. Previously

reported amounts have been amended. Previously reported amounts for organic capital expenditure are unchanged.

e 2016 includes amounts relating to the renewal of a 10% interest in the Abu Dhabi onshore oil concession for which new ordinary shares in BP were issued.
f The number of ordinary shares shown has been used to calculate the per share amounts.

* See Glossary.

240

BP Annual Report and Form 20-F 2016

Additional information

Non-operating items
Non-operating items are charges and credits included in the financial statements 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 c

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

Rosneft
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

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
Gulf of Mexico oil spill responsed
Otherc

Total before interest and taxation
Finance costsd
Taxation credit (charge)

Total after taxation

2016

2015

2,391
(8)
(373)
32
(289)

1,753

405
(73)
(300)
–
(56)

(24)

62
–
–
–
(39)

(1,204)
(24)
(410)
120
(717)

(2,235)

131
(108)
(607)
–
(6)

(590)

–
–
–
–
–

–

–
(134)
(90)
–
(6,640)
(55)

(170)
(151)
(71)
–
(11,709)
(155)

(6,919)

(12,256)

(5,167)
(494)
2,833

(15,081)
(247)
4,056

(2,828)

(11,272)

$ million

2014

(6,576)
(60)
(100)
430
8

(6,298)

(1,190)
(133)
(165)
–
(82)

(1,570)

225
–
–
–
–

225

(304)
(180)
(176)
–
(781)
(10)

(1,451)

(9,094)
(38)
4,512

(4,620)

a See Financial statements – Note 4 for further information on impairments.
b 2016 includes the write-off of $147 million in relation to the value ascribed to licences in the deepwater Gulf of Mexico, and $334 million in relation to the value ascribed to the BM-C-34 licence

in Brazil, both as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. 2016 also includes a $319-million reversal relating to Block KG D6 in India. 2014
includes a $395-million write-off relating to Block KG D6 in India.

c 2015 principally relates to BP’s share of impairment losses recognized by equity-accounted entities.
d See Financial statements – Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.

A
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BP Annual Report and Form 20-F 2016

241

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 operating cash flow excluding
amounts related to the Gulf of Mexico oil spill* and a strong focus on
capital discipline, providing a sound platform to grow shareholder
distributions. The initial priority is to address the dilution that arises
from the undiscounted scrip dividend alternative we currently have in
place. We would then aim to balance disciplined investment for even
stronger growth with our objective of growing distributions to
shareholders over the long term. 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.

While maintaining safe and reliable operations, preserving core growth
activities and with an ongoing commitment to sustaining the dividend,
our principal objective in the near term is to re-establish a balance in our
financial framework. This rebalanced framework is underpinned by the
resetting of both the capital and cash cost base of the group in response
to the lower price environment, as well as the growth in operating cash
flow we anticipate in our businesses. The group’s controllable cash
costs reduction target was reached a year ahead of schedule in 2016
and, including the impact of deals announced at the end of 2016, we
expect organic capital expenditure in 2017 to be between $15-17 billion.
We aim to manage gearing* within a 20-30% band while weak
market conditions remain and maintain a significant liquidity buffer. As
the portfolio additions are assimilated into our plans during 2017 and
we maintain our focus on both capital and costs, we expect to
continue to optimize our overall spend driving down the organic cash
rebalance point through the year. Operating cash flow excluding
amounts related to the Gulf of Mexico oil spill is expected to cover
organic capital expenditure and the dividend at around $60 per barrel
by the end of 2017. As we further assimilate recently announced
deals into our plans and maintain our focus on both capital and costs,
we will continue to optimize our overall spend driving the balance
point closer to $55 per barrel by the end of 2017. Based on our current
planning assumptions we would expect our cash balance point to
reduce to around $35-40 per barrel over the next five years.

Deepwater Horizon cash payments are expected to be in the range of
$4.5-5.5 billion in 2017 with the larger part of the outflow in the first
half of the year. With amounts to resolve the remaining business
economic loss claims expected to be substantially paid this year we
expect the total Deepwater Horizon cash payments to fall to around
$2 billion in 2018, and then to step down to a little over $1 billion per
annum from 2019. In 2017 we expect divestment proceeds to be in
the range of $4.5-5.5 billion, weighted towards the second half of the
year, and from 2018 to average the historical norm of around
$2-3 billion per annum.

We will keep our financial framework under review as we monitor oil
and gas prices and their impact on industry costs as we move through
2017 and beyond.

Dividends and other distributions to shareholders
The dividend is determined in US dollars, the economic currency of
BP, and the dividend level is regularly reviewed by the board. The
quarterly dividend was increased to 10 cents per share for the third
quarter of 2014 and has been maintained at this level in each
subsequent quarter.

The total dividend distributed to BP shareholders in 2016 was
$7.5 billion (2015 $7.3 billion). Shareholders have the option to receive
a scrip dividend in place of receiving cash. In 2016 the total dividend
paid in cash was $4.6 billion (2015 $6.7 billion).

Details of share repurchases to satisfy the requirements of certain
employee share-based payment plans are set out on page 278. There
were no other buyback programmes conducted during 2016.

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 49 for further information
on risks associated with prices and markets and Financial
statements – Note 28.

The group’s gross debt at 31 December 2016 amounted to
$58.3 billion (2015 $53.2 billion). Of the total gross debt, $6.6 billion is
classified as short term at the end of 2016 (2015 $6.9 billion). See
Financial statements – Note 25 for more information on the short-term
balance. Net debt* was $35.5 billion at the end of 2016, an increase
of $8.3 billion from the 2015 year-end position of $27.2 billion. The
ratio of gross debt to gross debt plus equity at 31 December 2016
was 37.6% (2015 35.1%). The ratio of net debt to net debt plus
equity* was 26.8% at the end of 2016 (2015 21.6%). See Financial
statements – Note 26 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 $23.5 billion at 31 December 2016 (2015
$26.4 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 robust cash position.

The group also has undrawn committed bank facilities of $7.4 billion
(see Financial statements – Note 28 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 levels of cash and cash equivalents,
and the ongoing ability to generate cash.

Standard & Poor’s Ratings’ long-term credit rating for BP is A negative
(stable outlook) and the Moody’s Investors Service rating is A2
(positive outlook).

The group’s sources of funding, its access to capital markets and
maintaining a strong cash position are described in Financial
statements – Note 24 and Note 28. 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 25 and Note 28.

During 2016 significant progress was made in resolving outstanding
claims arising from the 2010 Deepwater Horizon accident and oil spill.
As a result, a judgement has been made that a reliable estimate can
now be made for all remaining material liabilities arising from the
incident. Any further outstanding Deepwater Horizon related claims
are not expected to have a material impact on the group’s financial
performance. See Financial statements – Note 2 for further
information.

Off-balance sheet arrangements
At 31 December 2016, the group’s share of third-party finance debt of
equity-accounted entities was $14.6 billion (2015 $11.8 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, incremental to amounts recognized on the balance sheet,
at 31 December 2016 were $309 million (2015 $35 million) in respect
of liabilities of joint ventures* and associates* and $370 million
(2015 $163 million) in respect of liabilities of other third parties. Of
these amounts, $298 million (2015 $22 million) of the joint ventures
and associates guarantees relate to borrowings and for other third-
party guarantees, $338 million (2015 $119 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 27.

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 269 and Risk factors on page 49, 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.

242

BP Annual Report and Form 20-F 2016

Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2016 and the
proportion of that expenditure for which contracts have been placed.

Capital expenditure

Committed
of which is contracted

Total

2017

32,377
11,207

12,823
5,868

2018

9,060
3,462

2019

4,568
1,070

2020

2,588
427

2021

1,328
106

2022 and
thereafter

2,010
274

$ 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 2016, the group had committed to capital expenditure relating to investments in equity-accounted entities
amounting to $2,318 million. Contracts were in place for $2,083 million of this total.

The following table summarizes the group’s principal contractual obligations at 31 December 2016, 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 25 and more information on operating leases is given in Financial statements – Note 27.

$ million

Payments due by period

Expected payments by period under contractual obligations

Total

2017

2018

2019

2020

2021

Balance sheet obligations

Borrowingsa
Finance lease future minimum lease paymentsb
Decommissioning liabilitiesc
Environmental liabilitiesc
Gulf of Mexico oil spill liabilitiesd
Pensions and other post-retirement benefitse

Off-balance sheet obligations

Operating lease future minimum lease paymentsf
Unconditional purchase obligationsg

63,508
1,321
18,119
1,626
21,644
24,288

7,755
96
287
316
3,056
1,619

6,962
94
303
311
1,853
1,792

7,586
90
258
177
1,272
1,772

7,015
87
321
154
1,225
1,761

7,353
85
319
134
1,200
1,759

130,506

13,129

11,315

11,155

10,563

10,850

14,255
140,490

154,745

3,315
64,743

68,058

2,194
16,155

18,349

1,915
10,624

12,539

1,520
7,512

9,032

1,022
5,536

6,558

2022 and
thereafter

26,837
869
16,631
534
13,038
15,585

73,494

4,289
35,920

40,209

Total

285,251

81,187

29,664

23,694

19,595

17,408

113,703

a Expected payments include interest totalling $5,842 million ($1,162 million in 2017, $1,032 million in 2018, $895 million in 2019, $757 million in 2020, $618 million in 2021 and $1,378 million

thereafter).

b Expected payments include interest totalling $687 million ($54 million in 2017, $52 million in 2018, $47 million in 2019, $44 million in 2020, $40 million in 2021 and $450 million thereafter).
c The amounts are undiscounted.
d The amounts presented are undiscounted. Gulf of Mexico oil spill liabilities are included in the group balance sheet, on a discounted basis, within other payables. See Financial statements –

Note 2 for further information.

e 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.

f 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.

g 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 2017 include purchase commitments existing at 31 December 2016 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 28.

The following table summarizes the nature of the group’s unconditional purchase obligations.

A
d
d
i
t
i
o
n
a
l

d
i
s
c
l
o
s
u
r
e
s

Unconditional purchase obligations

Total

2017

Crude oil and oil products
Natural gas
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services

63,034
26,041
5,801
4,624
486
21,814
18,690

41,953
14,619
2,576
2,747
151
1,218
1,479

2018

7,312
4,544
1,413
856
137
1,028
865

2019

4,103
2,326
1,467
407
68
919
1,334

Total

140,490

64,743

16,155

10,624

$ million

Payments due by period

2021

2,020
1,097
38
90
18
1,286
987

5,536

2022 and
thereafter

4,682
1,897
78
365
51
16,063
12,784

35,920

2020

2,964
1,558
229
159
61
1,300
1,241

7,512

BP Annual Report and Form 20-F 2016

243

Upstream analysis by region

Our upstream operations are set out below by geographical area, with
associated significant events for 2016. BP’s percentage working
interest in oil and gas assets is shown in brackets. 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 supply 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) processing 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 markets including Japan, South Korea, China, the
Dominican Republic, Argentina, Brazil and Mexico.

Europe
BP is active in the North Sea and the Norwegian Sea. Our activities
focus on maximizing recovery from existing producing fields and new
field developments. BP’s production is generated from three key
areas: the Shetland area, comprising the Magnus, Clair, Foinaven and
Schiehallion fields; the central area, comprising the Bruce, Andrew
and ETAP fields; and Norway, through our equity accounted 30%
interest in Aker BP established in 2016 (see below).

• We announced that we doubled our interest in the Culzean

development in the UK Central North Sea in May, following the
acquisition of an additional 16% interest from JX Nippon. The
acquisition increases our interest in the development from 16% to
32%. The Maersk-operated Culzean field development was
sanctioned at the end of August 2015, and we expect production to
start in 2019 and continue into the 2030s.

• BP and Det norske oljeselskap announced the creation of an

independent oil and gas company in June, with the transaction
completing at the end of September. It combines the assets and
expertise from the Norwegian exploration and production operations
of both companies to form the largest Norwegian independent oil and
gas producer. Under the terms of the transaction, the BP Norge and
Det norske businesses have combined and been renamed Aker BP
ASA. Aker BP is independently operated and listed on the Oslo Stock
Exchange. It is owned by the former Det norske shareholder Aker
(40%), BP (30%) and independent shareholders (including other
former Det norske shareholders) (30%). Aker BP is an equity-
accounted associate over which BP has significant influence. Aker BP
benefits from the combined strength of Det norske’s efficient,
streamlined operating model and BP’s long experience in Norwegian
offshore operations, asset knowledge, technical skills and
international experience. BP received a cash payment of $250 million
including working capital and interest adjustments as part of the
transaction.

• On 2 October, 95 tonnes of oil in water was released to the sea
from the Clair platform, as a result of a technical issue with the
system designed to separate the mixed production fluids of water,
oil and gas. The release was stopped within an hour of the issue
being identified and Clair production was taken offline. Production
restarted on 25 October, resulting in a full-year production impact of
0.5mboe/d BP net.

• Operations at the Rhum gas field in the North Sea continue under a
licence issued by the US Office of Foreign Asset Control, which
licenses US persons and US owned and controlled companies to
support Rhum activities. This expires on 30 September 2017. Work is
ongoing to reduce BP’s reliance on US persons ahead of a new
licence application expected in the second quarter of 2017. The field
is owned by BP (50%) and the Iranian Oil Company (IOC) under a joint
operating agreement. EU sanctions and certain US secondary
sanctions in respect of Iran have been lifted or suspended as part of
the Joint Comprehensive Plan of Action. See International trade
sanctions on page 265.

244

BP Annual Report and Form 20-F 2016

• We made strong progress on the Quad 204 project in the

Schiehallion and Loyal fields, West of Shetland in 2016. Glen Lyon,
the replacement floating production, storage and offloading vessel
(FPSO) arrived on station in June 2016 and all 21 risers are now
attached. Final commissioning activities are underway with first oil
expected in 2017.

• On 24 January 2017 BP announced that it has agreed to sell 25% of
its 100% stake in Magnus, a 25% interest in a number of associated
pipelines and a 3% interest in the Sullom Voe Terminal (SVT) on
Shetland to EnQuest. The sale price of $85 million is expected to be
met by EnQuest from the sharing of future cash flows from the
assets and the agreement will not include any upfront payment to BP.
Under the terms of the agreement, EnQuest has an option,
exercisable between 1 July 2018 and 15 January 2019, to purchase
BP’s remaining 75% interest in Magnus, a further 9% interest in SVT
and the remainder of BP’s interests in the associated pipelines for a
consideration of $300 million. The deal remains subject to regulatory
and other third-party approvals.

In the UK 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 2016 of 439mboe/d. On 3 April 2017 BP
announced that it had agreed to sell the FPS business to INEOS for a
consideration of up to $250 million, subject to partner, regulatory and
other third-party approvals. BP also operates the Sullom Voe oil and
gas terminal in Shetland.
North America
Our upstream activities in North America take place in five areas:
deepwater Gulf of Mexico, the Lower 48 states, Alaska, Canada and
Mexico.
BP has around 300 lease blocks in the deepwater Gulf of Mexico,
making us one of the largest portfolio owners, and operates four
production hubs.
• In the first quarter of 2016 we completed evaluation of the Kepler 3
discovery well, drilled in late 2015, and this was tied into the Na
Kika platform and began production in the fourth quarter of 2016.
BP is the operator (50%), with Shell holding the other 50%.
• Also in the first quarter, a successful exploration well on the

Chevron-operated Guadalupe prospect (BP 50%) was completed.
Further appraisal drilling commenced in the fourth quarter. In
addition, an appraisal well in the Chevron-operated Tiber prospect
(BP 31%) was completed in the second quarter and a Suspension
of Production request was filed in September 2016. This notice is
used in situations where the licence is approaching expiry without
immediate plans for further drilling activity but where there are
plans for further development of the prospect.

• We completed drilling operations on two wells that commenced in
the fourth quarter of 2015; the Chevron-operated Gibson prospect
and the appraisal well on the Hopkins discovery. In the third quarter
of 2016 BP disposed of 33.3% of its working interest in the
Hopkins discovery to Anadarko, along with operatorship. BP’s
remaining working interest in the Hopkins discovery is 66.7%. In
the fourth quarter costs of $276 million were written off in relation
to Hopkins upon reclassification of the project to the development
phase. The Hopkins discovery is being renamed Constellation.
• In May we announced the start-up of the water injection major
project at the Thunder Horse platform (BP 75%). The project is
expected to extend the production life of the field and boost
recovery of oil and natural gas from one of the field’s three main
reservoirs. The project follows on from improvement work over the
last three years, including refurbishment of the platform’s existing
topsides and subsea equipment.

• We announced the start-up of the South Expansion major project at
our Thunder Horse platform in January 2017. Two producing wells
came online at start-up and two more will be delivered in the near
future. The project scope includes a new subsea production
system two miles to the south of the existing Thunder Horse
platform. The system is a collection point for four wells connected
to the platform by two lines installed on the seabed.

• In the fourth quarter of 2016 BP sanctioned the Mad Dog Phase 2
project, which will include a new floating production platform with
the capacity to produce up to 140,000 gross barrels of crude oil per
day from up to 14 production wells. Oil production is expected to

begin in late 2021. In 2013 BP (60.5% and operator) and
co-owners, BHP Billiton and Union Oil Company of California, an
affiliate of Chevron U.S.A. Inc., decided to re-evaluate the Mad Dog
Phase 2 project after an initial design proved too complex and
costly. Since then, BP has worked with co-owners and contractors
to simplify and standardize the platform’s design, reducing the
overall project cost by about 60%. Today, the leaner $9-billion
project, which also includes capacity for water injection, is
projected to be profitable at much lower oil prices. The second
Mad Dog platform will be moored approximately six miles to the
southwest of the existing platform. All partners in the project have
announced that they have taken a final investment decision (FID)
on Mad Dog Phase 2.

• During the year $233 million was written off in connection with

unsuccessful exploration activity on the Silvergate and Sweetwater
prospects.

• See also Significant judgement: oil and natural gas accounting on page

128 for further information on exploration leases.

The US Lower 48 onshore business has significant activities across
Arkansas, Colorado, New Mexico, Oklahoma, Texas and Wyoming
producing natural gas, oil, NGLs and condensate. It is organized into
five geographic business units, with a 1.4 billion boe proved reserve
base as at 31 December 2016, predominantly in unconventional
reservoirs (tight gas*, shale gas and coalbed methane). This resource
spans 3.1 million net developed acres and has approximately 9,700
operated gross wells, with daily net production around 300mboe/d.

Since the beginning of 2015, our US Lower 48 onshore business has
been operating as a separate business while remaining part of our
Upstream segment. It has its own governance, processes and
systems and is designed to increase competitive performance through
swift decision making and innovation, while maintaining BP’s
commitment to safe, reliable and compliant operations.

For further information on the use of hydraulic fracturing in our shale
gas assets see page 45. BP’s onshore US crude oil and product
pipelines and related transportation assets are included in the
Downstream segment.

In Alaska BP Exploration (Alaska) Inc. (BPXA) operated nine North
Slope oilfields in the Greater Prudhoe Bay area at the end of 2016. Our
focus continues to be safe and reliable operations, renewing BP’s
Alaska North Slope infrastructure and minimizing oil production
decline. Infrastructure renewal activities in 2016 included compressor
replacements, fire and gas system upgrades, safety system upgrades,
pipeline renewal and facility siting projects. BP’s daily net production
in Alaska in 2016 was 107.9mboe/d. Production decline is being
managed through annual drilling programmes and rig and non-rig
wellwork programmes. BP also owns significant interests in eight
producing fields operated by others, as well as a non-operating
interest in the Liberty prospect.

• In April the Point Thomson major project commenced production.

BP holds a 32% working interest in the field and ExxonMobil is the
operator.

• The Alaska LNG project concept includes a planned three train
North Slope gas treatment plant, approximately 800 miles of
pipeline to tidewater and a three-train liquefaction facility, with an
estimated capacity of 3bcf/d (up to 18.5 million tonnes per annum)
supplied from the Prudhoe Bay and Point Thomson fields. In early
2016, all co-venturers agreed that the current project cost of supply
is not competitive in the market. Furthermore, a study prepared by
WoodMackenzie in August 2016 confirmed this and identified
commercial levers that could enable the project to compete. In
December 2016 the producer parties agreed to terminate the
existing governance agreement and transition the project to be led
by the Alaska Gasline Development Corporation, a state entity. In
2017 the State of Alaska will progress the US Federal Energy
Regulatory Commission (FERC) permitting work, identify
commercial structure alternatives that deliver a competitive cost of
supply, and define a financing plan for future stages of the project.
On 22 January 2017 BP Alaska LNG LLC (BPAL) and AGDC
executed a Cooperation Agreement detailing BPAL’s commitment
to helping the state further its 2017 priorities, detailed above.
Future project milestones will be updated following the 2017
project re-definition and transition.

BP Pipelines (Alaska) Inc. (BPPA) owns a 49% interest in the Trans-
Alaska Pipeline System (TAPS). 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 BPPA, ExxonMobil
(21.1%) and ConocoPhillips (29.1%) of their intention to withdraw as
owners of TAPS. The transfer of Koch’s interest to the remaining
owners was completed in 2012. The remaining owners and Unocal
have not yet reached agreement regarding the terms for the transfer
of Unocal’s interest in TAPS.

• In November 2015, the FERC issued an order to BPPA addressing
the TAPS tariff rate filings for years 2009 and 2010 reducing the
approved tariff rate. As a result of the order, BPPA refunded
impacted shipping costs to BPXA and third-party shippers in 2016.
Due to these lower shipping costs, BPXA subsequently paid
material incremental production tax and royalty payments to the
State of Alaska in 2016 and January 2017 for the years 2009 and
2010 as well as 2011 to 2015.

In Canada, BP is focused on oil sands development as well as
pursuing offshore exploration opportunities. For our oil sands
development we 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
licences in the Canadian Beaufort Sea, Nova Scotia as well as
Newfoundland and Labrador.

• Following the start of oil production in March 2015 at the Sunrise
Phase 1 in-situ oil sands project in Alberta (BP 50%), production is
expected to ramp-up to 52,000 barrels per day (gross) in 2018.

• In 2016 BP (50%) and partner Hess (50%) submitted an

environmental impact statement for a drilling programme offshore
Nova Scotia which is planned to commence in 2018.

• In January 2016 BP was awarded three exploration licences in

partnership with Statoil and ExxonMobil in the Flemish Pass Basin
offshore of Newfoundland and Labrador, Canada (BP 33%) with
Statoil operating all three licences. Additionally, BP acquired interests
in two exploration licences from Statoil in the same basin (BP 10%).
Finally, in January 2017 BP was also the successful bidder in a further
four exploration blocks, of which three are in the West Orphan Basin
offshore of Newfoundland and Labrador (BP 50% and operator with
partners Hess and Noble Energy), and one in the East Orphan Basin
(BP 60% and operator with partner Noble Energy).

In Mexico, BP (33.3%) as a member of a consortium with Statoil and
Total was awarded two exploration blocks in the Deepwater bid round
1.4 held on 5 December 2016, Block 1 (2,381km2 in 2,437m water
depth) and Block 3 (3,287km2 in 1,763m water depth) in the Saline
Basin.

BP also conducts activity in Mexico through Pan American Energy LLC
(PAE), an equity-accounted joint venture* with Bridas Corporation, in
which BP has a 60% interest.

• On 30 October 2016, PAE, via its wholly owned subsidiary, Hokchi
S.A., became the first privately owned company to spud a well in
Mexico post Mexico’s reform of its energy industry. This is the first
of four commitment wells that will be drilled under the terms of
the licence agreement. In addition, on 12 December 2016, Hokchi
S.A. agreed to increase its working interest in the block from 60%
to 80% in a transaction with its partner, E&P Hydrocarboros y
Servicios, S.A.

South America
BP has upstream activities in Brazil and Trinidad & Tobago, and
through PAE, in Argentina and Bolivia. In February 2016 ANCAP, the
Uruguayan oil and gas regulator, approved the relinquishment of all of
our blocks in Uruguay.

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245

• In July BP Trinidad and Tobago LLC and ALNG announced the

sanction of the Trinidad onshore compression project. The project is
100% funded and owned by BP Trinidad and Tobago and will be
operated by ALNG. It is designed to increase production from
low-pressure wells in existing acreage in the Columbus Basin using
an additional inlet compressor at the Point Fortin Atlantic LNG plant.
The majority of the construction work will be undertaken by ALNG
with BP and other shareholder representation. The project is 95%
complete and start-up is planned for the second quarter of 2017.

Africa
BP’s upstream activities in Africa are located in Algeria, Angola, Egypt,
Libya, Mauritania and Senegal.

In Algeria BP, Sonatrach and Statoil are partners in the In Salah (BP
33.15%) and In Amenas (BP 45.89%) projects that supply gas to the
domestic and European markets.

• The Bourarhat agreement expired in September 2014 and talks
with Sonatrach to negotiate new terms were not successful.
Discussions with them to close out the project were initiated in the
first half of 2015 and are ongoing.

• The In Salah Southern Fields major project start-up was announced

in February 2016. The project is the latest stage in the
development of the In Salah Gas joint venture, which commenced
production in 2004.

• In July train 3 at In Amenas restarted following the completion of

repairs after the terrorist attack in January 2013.

• In November the start of testing and ramp-up activities at the In
Amenas compression project was announced. This project is
designed to enhance production in order to fill the capacity of all
three processing trains at the facility.

In Angola BP is present in seven major deepwater licences offshore
and is operator in three of these, blocks 18 and 31 that are producing
oil and block 24 that is in the exploration phase. BP’s block 19
exploration licence expired on 31 December 2016 and the block has
now been relinquished. BP also has an equity interest in the Angola
LNG plant (BP 13.6%).

• The Angola LNG plant, which had been shut down for planned
repairs since April 2014 restarted in 2016 and is producing and
supplying LNG and liquid cargoes to the global market.

• During the year, BP was involved in two discoveries in Angola,
Golfinho and Zalophus, the latter being a condensate discovery.
Further assessment of their potential commerciality is underway.

In Egypt BP and its partners currently produce 10% of Egypt’s
liquids* production and almost 30% of its gas production.

• On 26 February an exploration discovery was announced on the
Nooros East prospect in Egypt by the operator Eni who has now
tied it back for production. Eni holds a 75% interest in the Abu
Madi West concession, while BP holds a 25% interest. The well
was developed and commenced production in April 2016.
Additionally, a successful discovery in Nooros West was made in
the third quarter of 2016. Two wells are currently on production
from the West segment. This combined with further development
well drilling in the Nooros main segment, which was discovered in
July 2015, led to the total Nooros production increasing to
850mmscf/d of gas, and 7,000 barrels of condensate (154,000
barrels of oil equivalent gross per day), less than 18 months after
first gas.

• In June we announced the Baltim SW-1 gas discovery in the Baltim
South Development Lease in the East Nile Delta. The discovery,
which is located 12 kilometres from shoreline, is situated along the
same trend as the Nooros field discovered in July 2015. Following
appraisal of the discovery, BP and its partner Eni are working on
the development options for this discovery.

In Brazil BP has interests in 21 exploration concessions across five
basins.

• Our partner Anadarko took over from BP as operator of block
BM-C-32 (Itaipu) located in the Campos Basin. This transfer is
expected to facilitate the realization of development efficiencies for
this and the adjacent block, BM-C-30 (Wahoo), where Anadarko is
also the operator. BP continues to consider options for a potential
joint development of Itaipu/Wahoo or tie-back. A decision to move
into front-end engineering for a potential long- term test is planned
in 2017.

• In the third quarter of 2016 BP completed its analysis of the

prospectivity of block BM-C-34 and concluded that there were no
commercially viable prospects resulting in a write-off of
$601 million ($334 million as a non-operating item*). Asset
relinquishment is pending regulatory approval.

• After disappointing exploration results, BP and Petrobras

relinquished their interests in block BM-CE-2 in the Ceara basin. All
assets associated with the block have been written off between
2014 and 2016.

• In the fourth quarter of 2016 BP completed its seismic acquisition
programme in block BAR-M-346 in the Barreirinhas basin. The
seismic processing and prospect inventory development will be
progressed in 2017. An extension request was submitted to the
Brazilian National Petroleum Agency (ANP) and approved for the
block extending the licence until the end of 2019.

• BP continued to progress the preparatory activities for drilling

exploration wells in the Foz de Amazonas basin, with a
BP-operated well situated in block FZA-M-59, scheduled to spud in
early 2018. Additionally, BP expects drilling activity to commence
on its other non-operated interests in Foz de Amazonas in 2017 (BP
30%). An extension request was submitted to ANP and approved
for the five non-operated blocks extending the licence until the
third quarter of 2020.

• In the South Campos basin, Petrobras notified BP in August 2016
of their decision to exit from block BM-C-35. BP has taken over
operatorship and has a 100% working interest post Petrobras’ exit.
A revised appraisal plan was submitted to ANP and approved, the
decision to move into the second stage of the appraisal plan and
commit to an additional pre-salt well or end the appraisal plan is
expected in the third quarter of 2017.

In Argentina and Bolivia BP conducts activity through PAE.

• On 13 December 2016 the Bolivian Branch of PAE, E&P Bolivia
Limited, entered into, jointly with the other members of the
Caipipendi Consortium and Yacimientos Petroliferos Fiscales
Bolivianos, an addendum to the Caipipendi Operation Contract for
an extension of up to 15 years from the expiration of the original
term (2 May 2031) subject to certain investment and operational
conditions being met over the next five years. The addendum is
subject to the authority of the Bolivian National Congress and
approval is expected to be received in the first half of 2017.

• PAE signed an agreement on 7 December 2016 to acquire a 55%
working interest and operatorship in the Coiron Amargo Sur Este
Block located in the Vaca Muerte area of Neuquen, Argentina from
Madalena Energy, Inc.

In Trinidad & Tobago BP holds exploration and production licences and
PSAs covering 1.8 million acres offshore of the east and north-east
coast. Facilities include 13 offshore platforms and two onshore
processing facilities. Production comprises gas and associated liquids.

BP also has a shareholding in the Atlantic LNG (ALNG) liquefaction
plant, BP’s shareholding averages 39% across four LNG trains* 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 LNG
from 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
remaining 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.

246

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• Also in June we announced, together with the Egyptian Natural

Gas Holding Company (EGAS), that we had sanctioned
development of the Atoll Phase 1 project. The project is an early
production scheme involving the conversion of the existing
exploration well to a producing well, the drilling of two additional
wells and the installation of the necessary tie-ins and facilities
required to produce from the field, and is expected to bring gas to
the Egyptian domestic gas market starting in the first half of 2018.
BP has a 100% interest in the concession. BP recently completed
multiple transportation and processing agreements to accelerate
the development of the Atoll field. Onshore processing will be
handled by the existing West Harbour gas processing facilities. BP
announced the Atoll discovery in March 2015.

• In September we announced we had signed concession

amendments for the Temsah (BP 50%), Ras El Barr (BP 50%) and
Nile Delta offshore (BP 25%) concessions in Egypt. These
amendments allow for the economic development of the Nooros
field in the Nile Delta offshore concession.

• Following the devaluation of the Egyptian pound on 3 November
2016, the IMF approved a $12 billion extended fund facility, S&P
upgraded its outlook for Egypt to ‘Stable’ and Egypt’s foreign
currency reserves increased from $19 billion in October 2016 to
$23 billion in December 2016.

• In November BP announced that it had agreed to buy a 10%

interest in the Shorouk concession offshore Egypt, which contains
the Zohr gas field from Eni, for $375 million plus reimbursement of
Eni’s past expenditure from 1 January 2016 up to completion of
the deal. The deal completed on 23 February. The transaction also
includes the option to buy an additional 5% interest on the same
terms by 31 December 2017. First gas is expected in 2017.

In Libya we partner with the Libyan Investment Authority (LIA) in an
exploration and production-sharing agreement (EPSA) to explore
acreage in the onshore Ghadames and offshore Sirt basins (BP 85%).
BP and the LIA served the National Oil Corporation (NOC) with notices
of force majeure in August 2014 as a result of underlying
circumstances which rendered the delivery of the EPSA obligations
impossible. BP and the NOC signed an Interim Arrangement
Agreement in January 2016 under which the EPSA did not terminate
automatically in August 2016 (two years from the notice of force
majeure). BP wrote off all balances associated with the Libya EPSA in
2015.

In December BP announced that it had signed agreements with
Kosmos Energy to acquire a 62% working interest, including
operatorship, of Kosmos’ exploration blocks in Mauritania and a
32.49% effective working interest in Kosmos’ Senegal exploration
blocks. Together these blocks cover approximately 33,000km2. BP
intends to invest nearly $1 billion, mostly in the form of a multi-year
exploration and development carry to acquire a 62% interest and
operatorship of offshore Blocks C-6, C-8, C-12 and C-13 in Mauritania
and an effective 32.49% interest in the Saint-Louis Profond and Cayar
Profond blocks in Senegal. Under the terms of the agreements, BP
and Kosmos have also agreed that Kosmos will remain the technical
operator for the exploration phase of the project and drill three new
exploration wells beginning in 2017. In addition to the existing blocks,
the companies have agreed to co-operate in areas of mutual interest in
offshore Mauritania, Senegal and the Gambia with Kosmos acting as
the exploration operator and BP as the development operator. The
Mauritania agreement completed in December and the Senegal
agreement in February 2017.

In June 2016 BP’s non-operated Tarhazoute offshore (BP 45%) and
Foum Assaka offshore (BP 26.3%) licences in Morocco were not
extended and lapsed. This was in agreement with partners and
followed a detailed review of the prospects. Exit is in progress on BP’s
third licence in Morocco – the Essaouira offshore licence (BP 45%).

Asia
BP has activities in Western Indonesia, China, Azerbaijan, Oman, Abu
Dhabi, India, Iraq, Russia and Kuwait.

In November BP completed the sale of all of its interests in the Sanga-
Sanga PSA (BP 38%) in Western Indonesia operated by Virginia
Indonesia Company LLC (VICO) to subsidiaries of PT. Saka Energi
Indonesia by a share sale.

In China BP has a 30% equity stake in the Guangdong LNG
regasification terminal and trunkline project with a total storage
capacity of 640,000m3, making it the first and only international oil
company invested in China’s LNG import infrastructure. The project is
supplied under a long-term contract with Australia’s North West Shelf
venture (BP 16.67%).

• In March BP and China National Petroleum Corporation (CNPC)
signed a production-sharing contract for shale gas exploration,
development and production in the Neijiang-Dazu block in the
Sichuan Basin, China. The contract is BP’s first shale gas PSC in
China and covers an area of approximately 1,500km2. CNPC will be
operator for this project.

• In September we announced that we had signed a second PSC for
shale gas exploration, development and production with CNPC.
The PSC covers an area of approximately 1,000km2 at Rong Chang
Bei in the Sichuan Basin.

In Azerbaijan, BP operates two PSAs, Azeri-Chirag-Gunashli (ACG) (BP
35.8%) and Shah Deniz (BP 28.83%) and also holds a number of other
exploration leases.

• In 2012 certain EU and US regulations concerning restrictive

measures against Iran were issued, which impact the Shah Deniz
joint venture in which Naftiran Intertrade Co Ltd (NICO), a
subsidiary of the National Iranian Oil Company, holds a 10%
interest. The EU sanctions and certain US secondary sanctions in
respect of Iran have been lifted or suspended as part of the Joint
Comprehensive Plan of Action. For further information see
International trade sanctions on page 265.

• In May BP and the State Oil Company of the Republic of Azerbaijan
(SOCAR) signed a memorandum of understanding, followed by a
heads of agreement in November, to jointly explore potential
prospects in Block D230 in the North Absheron basin in the
Azerbaijan sector of the Caspian Sea.

• Implementation of the Shah Deniz Stage 2 project continues

successfully. In May, the Shah Deniz consortium announced the
award of a $1.5 billion contract for the transport and installation of the
deeperwater subsea production systems for Shah Deniz Stage 2. In
September the jacket for one of the Shah Deniz Stage 2 platforms
commenced its journey for offshore installation. The Shah Deniz
Stage 2 project is now more than 83% complete in terms of
engineering, procurement and construction, and remains on target for
first gas in 2018.

• In December the Azerbaijan International Operating Company and

the ACG Joint Operating Company operated by BP, signed a
non-binding letter of intent with SOCAR covering the future
development of the AGC field in the Azerbaijan sector of the
Caspian Sea. The agreement will cover the development of the
field until the end of 2049. The letter of intent agrees the key
commercial terms for the contract extension and enables the
parties to proceed with negotiations and finalize fully-termed
agreements.

BP holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan
(BTC) oil pipeline. The 1,768km 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 pipeline has a capacity of
1mmboe/d with an average throughput in 2016 of 694mboe/d.

BP is technical operator of, and currently holds a 28.83% interest in,
the 693km South Caucasus Pipeline (SCP). The pipeline takes gas
from Azerbaijan through Georgia to the Turkish border and has a
capacity of 143mboe/d with average throughput in 2016 of
121mboe/d. BP (as operator of Azerbaijan International Operating
Company) also operates the Western Export Route Pipeline that
transports ACG oil to Supsa on the Black Sea coast of Georgia, with an
average throughput of 83mboe/d in 2016.

BP also holds a 12% interest in the Trans Anatolian Natural Gas
Pipeline that will transport Shah Deniz gas across Turkey, and a 20%
interest in the Trans Adriatic Pipeline that will take gas through Greece
and Albania into Italy.

BP Annual Report and Form 20-F 2016

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In Oman, BP is continuing with development activity on the
BP-operated Khazzan field in block 61 (BP 60%).

• As at 31 December 2016 the Khazzan major project was 92.5%
complete and on track to deliver first gas in the second half of
2017. The vast majority of the infrastructure is already in place
including roads, power lines and a 60km water pipeline from
Hanya. The two-train central gas processing facility has also
progressed well and is 97% complete. Mechanical completion and
handover to commissioning has commenced. The water treatment
plant, waste management area and electricity substation have also
been completed along with accommodation units for the workforce
of up to 13,000. The Khazzan drilling programme is also on track
with 45 of the 50 wells needed by first gas already drilled. Thirty
well sites are mechanically completed and connection to the
central gas processing facility via the duplex gathering system is on
track for the second quarter of 2017.

• In November BP and Oman Oil Company Exploration & Production
signed an agreement, announced in February, with the government
of the Sultanate of Oman amending the Oman Block 61 exploration
and production-sharing agreement (EPSA) to extend the licence
area, paving the way for further development of the Khazzan field.
The extension adds more than 1,000km2 to the south and west of
the original 2,700km2 of Block 61. The extension will allow a second
phase of development, accessing additional gas in the area already
identified by drilling activity within the original block. Development
of this additional resource is subject to final approval of the
government of Oman and of BP – both expected in 2017.

In Abu Dhabi, we have an equity interest of 14.67% in an offshore
concession. We also have a 10% equity shareholding in the Abu Dhabi
Gas Liquefaction Company that supplied approximately 5.9 million
tonnes of LNG (306bcfe regasified).

• In December BP signed an agreement with the Supreme Petroleum
Council of the Emirate of Abu Dhabi, in its capacity as representative
of the government, and the Abu Dhabi National Oil Company
(ADNOC) that grants BP a 10% interest in the Abu Dhabi ADCO
onshore oil concession. In addition to the interest in the ADCO
concession, BP becomes a 10% shareholder in OPCO, the Abu Dhabi
Company for Onshore Petroleum Operations Limited, which operates
the concession. The agreement includes BP becoming asset leader
for the Bab asset group within the concession. The other partners in
this concession are ADNOC (60%), Total (10%), INPEX (5%), and GS
Energy (3%). Renewal of the ADCO concession interest (covering
materially the same acreage as BP’s prior interest that expired in
2014) to 31 December 2054 provides BP with long-term access to
significant and competitive production and reserves.

In March 2016 we announced that BP and Kuwait Petroleum
Corporation have signed a framework agreement to explore possible
joint opportunities for investment and co-operation in future oil, gas,
trading and petrochemicals ventures. In addition to enhancing oil and
gas recovery from Kuwait’s existing resource base, the agreement
also includes the intention to study opportunities for joint investment
in future oil and gas exploration both inside Kuwait and globally. Other
elements of the agreement cover possible future oil and gas trading
deals including LNG trading and related ventures. In March 2016 BP
also signed an Enhanced Technical Service Agreement for south and
east Kuwait conventional oilfields, which includes the Burgan field,
with Kuwait Oil Company.

In India, we have a 30% participating interest in three oil and gas PSAs
operated by Reliance Industries Limited (RIL), and have a stake with
RIL in a 50:50 joint venture (India Gas Solution Private Limited) for the
sourcing and marketing of gas in India.

• On 21 March 2016, the government of India issued a natural gas

pricing policy which allows pricing and marketing freedom for new
discoveries in deep water, ultra deep water, and high pressure high
temperature reservoirs. In light of this, BP and its partners are
progressing the investment plans to develop the discovered
resources.

• In the fourth quarter of 2016 we recorded a $234-million

impairment reversal and a $319-million reversal of exploration
write-off relating to Block KG D6 in India. This reversal is mainly
driven by an increased confidence in the progress of projects by BP
and its partners.

• Block CYD5 was relinquished in 2016 due to lack of material

accumulations and poor future exploration prospectivity, resulting
in an exploration write-off of $216 million.

In Iraq, BP holds a 47.6% working interest and is the lead contractor in
the Rumaila technical service contract in southern Iraq. Rumaila is one
of the world’s largest oil fields, comprising five producing reservoirs.
Despite continued instability and sectarian violence in the north and
west of the country, BP operations continued as planned in the south.

In Russia, in addition to its 19.75% equity interest in Rosneft, BP
holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas), a joint
venture with Rosneft that is developing the Srednebotuobinskoye oil
and gas condensate field in East Siberia (see Rosneft on page 35 for
further details).

• In October 2016 Rosneft and BP completed a transaction to create
a new joint venture, Yermak Neftegaz LLC, to conduct onshore
exploration in the West Siberian and Yenisei-Khatanga basins.
Yermak Neftegaz is 51% owned by Rosneft and 49% by BP, and
currently holds seven exploration and production licences. The
venture will also carry out further appraisal work on the
Baikalovskoye field, an existing Rosneft discovery in the Yenisei-
Khatanga area of mutual interest.

Australasia
BP has activities 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 the
region, 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 year.

BP is also one of five participants in the Browse LNG venture
(operated by Woodside) and holds a 17.33% interest.

• In March 2016, following substantial completion of front-end

engineering and design (FEED) work, the Browse joint venture
participants decided not to progress with the floating LNG
development at that time due to the economic and market
environment. The Browse joint venture participants are evaluating
and narrowing a range of alternative development options, and will
select one in 2018.

• The NWS Persephone project (BP 16.67%) is on schedule to

deliver first gas in the second half of 2017 and is the second of the
NWS series of subsea tie-back projects that have been undertaken
to extend the production plateau and supply additional gas to the
NWS’s five existing LNG trains and domestic gas plant. The project
is operated by Woodside.

• In October BP announced it had taken the decision not to progress
an exploration drilling programme in the Great Australian Bight
(GAB), offshore South Australia. The decision follows the review
and refresh of BP’s upstream strategy earlier this year. BP has
determined that the GAB project would not be able to compete for
capital investment with other upstream opportunities in its global
portfolio in the foreseeable future and the related assets have been
written off.

BP’s 5.375% interest in the Jansz-lo field and its 12.5% interests in
the Geryon, Orthrus, Maenad, Urania and Eurytion fields (which are
part of the Greater Gorgon project) were sold in June 2016.

248

BP Annual Report and Form 20-F 2016

In Papua Barat, Eastern Indonesia, BP operates the Tangguh LNG
plant. In 2016 BP increased its interest in Tangguh from 37.16% to
40.22%. 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.

• In July BP announced that the FID for the development of the

Tangguh expansion project had been approved. The FID allows
the project to continue with the planned investment to build a
third LNG processing train (train 3), adding 3.8 million tonnes per

annum of production capacity to the existing facility, bringing total
plant capacity to 11.4 million tonnes per annum. The project also
includes two offshore platforms, 13 new production wells, an
expanded LNG loading facility, and supporting infrastructure. This
will enable BP to play an important role in supporting Indonesia’s
growing energy demand, with 75% of its annual LNG production
sold to the Indonesian state electricity company PT. PLN
(Persero). First production from train 3 is expected in 2020.
• In November BP received approval from the government of

Indonesia to relinquish its 100% interests in the West Aru I and II
PSAs. Approval to relinquish its 32% interests in the Chevron-
operated West Papua I and Ill PSAs is still pending.

Downstream plant capacity
The following table summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2016.

Fuels value chain
US
US North West
US East of Rockies

Europe
Rhine

Iberia

Rest of world
Australia
New Zealand
Southern Africa

Total BP share of capacity at 31 December 2016

Country

Refinery

Cherry Point
Whiting
Toledo

Germanyc

Netherlands
Spain

Bayernoild
Gelsenkirchen
Lingen
Rotterdam
Castellón

Australia
New Zealand Whangareid
South Africa

Kwinana

Durband

Crude distillation capacitiesa

Group interestb
(%)

BP share
thousand barrels
per day

100
100
50

10
100
100
100
100

100
21.2
50

236
430
80
746

22
265
95
377
110
869

149
26
90
265
1,880

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 On 31 December 2016 we completed the dissolution of our German refining joint operation* with Rosneft. The capacities reported here reflect BP’s share of capacities after the dissolution.
d Indicates refineries not operated by BP.

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Petrochemicals production capacitya
The following table summarizes BP group’s share of petrochemicals production capacities as at 31 December 2016.

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 2016

BP share of capacity
thousand tonnes per annumb

Site

Group interestc
(%)

PTA

Acetic
acid

Olefins and
derivatives

Cooper River
Texas City

Hulle
Geel
Gelsenkirchenf
Mülheimf

Point Lisas
Caojing
Chongqing
Nanjing
Zhuhaig
Merak
Ulsan
Kertih
Mai Liao
Taichung

100
100

100
100
100
100

36.9
50
51
50
85
100
34-51
70
50
61.4

1,400
–

1,400

–
1,300
–
–

1,300

–
–
–
–
2,500
500
–
–
–
500

3,500

6,200

–
900

900

–
700
–
–

700

–
–
–
–
–
–
–
–
–
–

–

1,600

–
600d

600

500
–
–
–

500

–
–
200
300
–
–
300h
400
200
–

1,400

2,500

–
–

–

–
–
3,300
–

3,300

–
3,500
–
–
–
–
–
–
–
–

3,500

6,800

Product

Others

–
100

100

200
–
–
300

500

700
–
100
–
–
–
100h
–
–
–

900

1,500

18,600

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 non-operated equity-accounted entities, as indicated.
d Group interest is quoted at 100%, reflecting the capacity entitlement, which is marketed by BP.
e The site has capacity under 100,000 tonnes per annum for a speciality product (e.g. naphthalene dicarboxylate and ethylidene diacetate).
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. On

31 December 2016 we completed the dissolution of our German refining joint operation with Rosneft. The capacities reported here reflect BP’s share of capacities after the dissolution.

g BP Zhuhai Chemical Company Ltd is a subsidiary* of BP, the capacity of which is shown above at 100%.
h Group interest varies by product.

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BP Annual Report and Form 20-F 2016

Oil and gas disclosures for the
group
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 of the transaction. 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 2016 BP had material volumes of proved undeveloped
reserves held for more than five years in Trinidad, the North Sea,
Egypt, Canada 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 a weighted
average 18% (18% for 2015 five-year average) of our group proved
undeveloped reserves (including the impact of disposals and price
acceleration effects in PSAs) to proved developed reserves. This
equates to a turnover time of about five and a half years. We expect
the turnover time to remain near this level and anticipate the volume
of proved undeveloped reserves held for more than five years to
remain about the same.

Proved reserves as estimated at the end of 2016 meet BP’s criteria for
project sanctioning and SEC tests for proved reserves. We have not
halted or changed our commitment to proceed with any material
project to which proved undeveloped reserves have been attributed in
light of lower oil and gas prices. BP has responded to the downturn in
prices by enhancing the efficiency and productivity of our operations.

In 2016 we progressed 1,134mmboe of proved undeveloped reserves
(586mmboe for our subsidiaries* alone) to proved developed
reserves through ongoing investment in our subsidiaries’ and equity-
accounted entities’ upstream development activities. Total
development expenditure, excluding midstream activities, was
$14,143 million in 2016 ($11,145 million for subsidiaries and
$2,998 million for equity-accounted entities). The major areas with
progressed volumes in 2016 were Argentina, Iraq, Trinidad, Russia
and the US. Revisions of previous estimates for proved undeveloped
reserves are due to changes relating to field performance, well results
or changes in commercial conditions including price impacts; there
were no individually material revisions during the year. The following
tables describe the changes to our proved undeveloped reserves
position through the year for our subsidiaries and equity-accounted
entities and for our subsidiaries alone.

Subsidiaries and equity-accounted entities

volumes in mmboea

Proved undeveloped reserves at 1 January 2016
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales

Total in year proved undeveloped reserves changes
Proved developed reserves reclassified as

undeveloped

Progressed to proved developed reserves by

development activities (e.g. drilling/completion)

Proved undeveloped reserves at 31 December 2016

7,687
376
177
457
271
(59)

1,222

(1,134)

7,797

Subsidiaries only

volumes in mmboea

Proved undeveloped reserves at 1 January 2016
Revisions of previous estimates
Improved recovery
Discoveries and extensions
Purchases
Sales

Total in year proved undeveloped reserves changes
Proved developed reserves reclassified as

undeveloped

Progressed to proved developed reserves by

development activities (e.g. drilling/completion)

Proved undeveloped reserves at 31 December 2016

4,211
185
170
75
54
(57)

427

(586)

4,068

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:

• well data used to assess the local characteristics and conditions of

reservoirs and fluids

* See Glossary.

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• field scale seismic data to allow the interpolation and extrapolation
of these characteristics outside the immediate area of the local
well control

• data from relevant analogous fields.

Well data includes appraisal wells or sidetrack holes, full logging
suites, core data and fluid samples. BP considers the integration of
this data in certain cases to be superior to a flow test in providing
understanding of overall reservoir performance. The collection of data
from logs, cores, wireline formation testers, pressures and fluid
samples calibrated to each other and to the seismic data can allow
reservoir properties to be determined over a greater volume than the
localized volume of investigation associated with a short-term flow
test. There is a strong track record of proved reserves recorded using
these methods, validated by actual production levels.

Governance
BP’s centrally controlled process for proved reserves estimation
approval forms part of a holistic and integrated system of internal
control. It consists of the following elements:

• Accountabilities of certain officers of the group to ensure that there
is review and approval of proved reserves bookings independent of
the operating business and that there are effective controls in the
approval process and verification that the proved reserves
estimates and the related financial impacts are reported in a timely
manner.

• Capital allocation processes, whereby delegated authority is

exercised to commit to capital projects that are consistent with the
delivery of 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 immediate review and all proved
reserves require annual central authorization and have scheduled
periodic reviews. The frequency of periodic review ensures that
100% of the BP proved reserves base undergoes central review
every three 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 more than 10 years 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

252

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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 are estimated or assured 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 2016, of certain properties owned by Rosneft as part of
our equity-accounted proved reserves. The properties evaluated by
D&M account for 100% of Rosneft’s net proved reserves as of
31 December 2016. The net proved reserves estimates prepared by
D&M were prepared in accordance with the reserves definitions of
Rule 4-10(a)(1)-(32) of Regulation S-X. All reserves estimates involve
some degree of uncertainty. BP has filed D&M’s independent report
on its reserves estimates as an exhibit to this 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 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
86% of our total proved reserves of subsidiaries at 31 December 2016
were held through joint operations* (84% in 2015), and 31% of the
proved reserves were held through such joint operations where we
were not the operator (34% in 2015).

Estimated net proved reserves of crude oil at 31 December 2016a b c

UK
Rest of Europe
US
Rest of North Americad
South America
Africa
Rest of Asia
Australasia

Subsidiaries
Equity-accounted entities

Total

Developed

Undeveloped

155
–
826
42
9
317
1,107
32

2,487
3,573

6,060

274
–
497
209
11
42
245
14

1,291
2,529

3,819

million barrels

Total

429
–
1,322
251
20
358
1,352
46

3,778
6,101

9,879

Estimated net proved reserves of natural gas liquids at 31 December 2016a 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

13
–
226
–
5
13
–
9
266
65
331

3
–
73
–
28
1
–
2
107
17
123

Total

16
–
299
–
33
14
–
11
373
81
454

excluding acquisitions and disposals was 109% (61% in 2015 and
63% in 2014) for subsidiaries and equity-accounted entities, 101% for
subsidiaries alone and 121% for equity-accounted entities alone.
There were material reductions (162mmboe) of reserves due to
accelerations of the date of cessation of production in the US due to
lower oil and gas prices, but these were largely offset by increases
(157mmboe) in PSAs, principally in Azerbaijan, Indonesia and Iraq
resulting from increased cost recovery volumes due to lower oil and
gas prices. The 2016 RRR was impacted to a significant degree by the
renewal of the ADCO concession in Abu Dhabi. Excluding the impact
of the renewal, the total RRR would have been 70%.

In 2016 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted to
1336mmboe (742mmboe for subsidiaries and 594mmboe for
equity-accounted entities), through revisions to previous estimates,
improved recovery from, and extensions to, existing fields and
discoveries of new fields. These additions include volumes associated
with the renewal of the 9.5% interest in the ADCO onshore
concession. 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 2016
principally resulted from the application of conventional technologies
and increases in PSA entitlement as a result of lower prices. The
principal proved reserves additions in our subsidiaries were in
Indonesia, Iraq, UAE and the US. We had material reductions in our
proved reserves in the US principally due to lower oil and gas prices.
The principal reserves additions in our equity-accounted entities were
in Argentina and Russia.

16% of our proved reserves are associated with PSAs. The countries
in which we operated under PSAs in 2016 were Algeria, Angola,
Azerbaijan, Egypt, India, Indonesia and Oman. In addition, the
technical service contract (TSC) governing our investment in the
Rumaila field in Iraq functions as a PSA.

Our Abu Dhabi offshore concessions are due to expire in 2018, we
have no proved reserves associated with these concessions beyond
their expiry date. 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 194.

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Estimated net proved reserves of liquids*

Subsidiaries
Equity-accounted entities

Total

Developed

Undeveloped

2,753
3,637

6,390

1,398
2,545

3,943

million barrels

Total

4,151e f
6,183g

10,333

Estimated net proved reserves of natural gas at 31 December 2016a b

UK
Rest of Europe
US
Rest of North America
South America
Africa
Rest of Asia
Australasia

Subsidiaries
Equity-accounted entities

Total

billion cubic feet

Developed Undeveloped

499
–
5,447
–
1,784
767
1,890
3,012

13,398
7,617

21,015

350
–
2,567
–
4,970
2,191
3,769
1,643

15,490
6,863

22,353

Total

848
–
8,014
–
6,755
2,958
5,659
4,654

28,888h
14,480i

43,368

Estimated net proved reserves on an oil equivalent basis

Subsidiaries
Equity-accounted entities

Total

million barrels of oil equivalent

Developed Undeveloped

5,063
4,951

10,014

4,068
3,729

7,797

Total

9,131
8,679

17,810

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 2016 marker prices used were Brent* $42.82/bbl (2015 $54.17/bbl and 2014

$101.27/bbl) and Henry Hub* $2.46 /mmBtu (2015 $2.59/mmBtu and 2014 $4.31/mmBtu).

c Includes condensate.
d All of the reserves in Canada are bitumen.
e Proved reserves in the Prudhoe Bay field in Alaska include an estimated 9 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.

f Includes 16 million barrels of liquids in respect of the 30% non-controlling interest in BP

Trinidad and Tobago LLC.

g Includes 347 million barrels of liquids in respect of the non-controlling interest in Rosneft

held assets in Russia including 28 million barrels held through BP’s equity-accounted interest
in Taas-Yuryakh Neftegazodobycha.

h Includes 2,026 billion cubic feet of natural gas in respect of the 30% non-controlling interest

in BP Trinidad and Tobago LLC.

i Includes 300 billion cubic feet of natural gas in respect of the non-controlling interest in
Rosneft held assets in Russia including 3 billion cubic feet held through BP’s equity-
accounted interest in Taas-Yuryakh Neftegazodobycha.

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 2016, on an oil
equivalent basis including equity-accounted entities, increased by 4%
(decrease of 1% for subsidiaries and increase of 9% for equity-
accounted entities) compared with 31 December 2015. Natural gas
represented about 42% (55% for subsidiaries and 29% for equity-
accounted entities) of these reserves. The change includes a net
increase from acquisitions and disposals of 520mmboe (decrease of
128mmboe within our subsidiaries and increase of 648mmboe within
our equity-accounted entities). Acquisition activity in our subsidiaries
occurred in Abu Dhabi (increase of interest in the ADCO onshore
concession from 9.5% to 10%), Indonesia, the US and the UK, and
divestment activity in our subsidiaries in Norway, Indonesia, Australia,
Trinidad and the US. In our equity-accounted entities the most
significant items were purchases in Russia, Norway and Venezuela.
The proved reserves replacement ratio* (RRR) 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 2016, the proved reserves replacement ratio

BP Annual Report and Form 20-F 2016

253

BP’s net production by country – crude oila and natural gas liquids

2016

2015

Crude oil
2014

2016

2015

Natural gas
liquids
2014

thousand barrels per day

BP net share of productionb

Subsidiaries
UKc d

Norwayc

Total Rest of Europe

Total Europe

Alaskac

Lower 48 onshorec

Gulf of Mexico deepwater

Total US

Canadae

Total Rest of North America

Total North America

Trinidad & Tobagoc

Total South America

Angola

Egyptc

Algeria

Total Africa

Azerbaijanc

Western Indonesiac

Iraqf

India

Total Rest of Asia

Total Asia

Australiac

Eastern Indonesiac

Total Australasia

Total subsidiaries

Equity-accounted entities (BP share)

Rosneft (Russia, Canada, Venezuela, Vietnam)

Abu Dhabig

Argentina

Bolivia

Egypt

Norwayc

Russiac

Other

102

107

216

335

347

219

263

105

204

943

836

101

–

110

107

203

323

327

221

270

111

199

933

809

–

127

206

347

–

347

181

222

147

834

816

–

Total equity-accounted entities

Total subsidiaries and equity-accounted entitiesh

1,015

1,958

974

1,908

979

1,813

–

104

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 2016, BP increased its interests in Tangguh in Indonesia and the Culzean asset in the UK North Sea, and in certain US onshore assets. It disposed of its interests in the Valhall, Skarv and Ula
assets in the Norwegian North Sea and in return received an interest in Aker BP ASA, which operates in Norway. It also disposed of its interests in the Jansz-Io asset in Australia, and the Sanga
Sanga conventional concession in Indonesia. It also decreased its interests in certain Trinidad and US onshore assets. In 2015, BP acquired an interest in Taas-Yuryakh Neftegazodobycha. It
also increased its interest in the North Alexandria and West Mediterranean Deep Water Concessions of the West Nile Delta project in Egypt. It increased its interest in certain UK North Sea,
Trinidad, and US onshore assets. It also decreased its interest in certain other assets in the same regions. In 2014, BP divested its interests in the Endicott and Northstar fields, and 50% of its
interests in the Milne Point field, in Alaska and 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.

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 All of the production from Canada in Subsidiaries is bitumen.
f Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There is no impact on the financial results.

g BP holds interests, through associates, in offshore concessions in Abu Dhabi which expire in 2018.
h Includes 3 net mboe/d of NGLs from processing plants in which BP has an interest (2015 4mboe/d and 2014 7mboe/d).

Because of rounding, some totals may not agree exactly with the sum of their component parts.

254

BP Annual Report and Form 20-F 2016

BP’s net production by country – natural gas

Subsidiaries
UKb

Norwayb
Total Rest of Europe

Total Europe

Lower 48 onshoreb

Gulf of Mexico deepwater

Alaska

Total US

Canada

Total Rest of North America

Total North America

Trinidad & Tobagob

Total South America

Egyptb

Algeria

Total Africa

Azerbaijanb
Western Indonesiab

India

Total Rest of Asia

Total Asia

Australiab

Eastern Indonesiab

Total Australasia

Total subsidiariesc

Equity-accounted entities (BP share)

Rosneft (Russia, Canada, Venezuela, Vietnam)
Argentina

Bolivia

Norwayb

Angola

Western Indonesiab

Total equity-accounted entitiesc

Total subsidiaries and equity-accounted entities

million cubic feet per day

BP net share of productiona

2016

2015

2014

170
82

252

155
111

111

266

71
102

102

173

1,476

1,353

1,350

173

168

159

1,656

1,528

1,519

1,666

1,689

305

208

513

245
35

363

451

369

820

1,538

1,922

402

187

589

219
48

113

380

447

354

801

1,529

2,147

406

107

513

230
47

131

408

450

364

814

5,302

5,495

5,585

1,279
354

1,195
341

1,084
323

–

1,773

7,075

1,651

7,146

1,515

7,100

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 2016, BP increased its interests in Tangguh in Indonesia and the Culzean asset in the UK North Sea, and in certain US onshore assets. It disposed of its interests in the Valhall, Skarv and Ula
assets in the Norwegian North Sea and in return received an interest in Aker BP ASA, which operates in Norway. It also disposed of its interests in the Jansz-Io asset in Australia, and the Sanga
Sanga concession in Indonesia. It also decreased its interests in certain Trinidad and US onshore assets. In 2015, BP acquired an interest in Taas-Yuryakh Neftegazodobycha. It also increased
its interest in the North Alexandria and West Mediterranean Deep Water Concessions of the West Nile Delta project in Egypt. It increased its interest in certain UK North Sea, Trinidad, and US
onshore assets. It also decreased its interest in certain other assets in the same regions. 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.

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.

Because of rounding, some totals may not agree exactly with the sum of their component parts.

BP Annual Report and Form 20-F 2016

255

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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 production (realizations*)a

$ per unit of production

Subsidiaries

2016

Crude oilc
Natural gas liquids
Gas

2015

Crude oilc d
Natural gas liquids
Gas

2014

Crude oilc d
Natural gas liquids
Gas

Equity-accounted entitiese

2016

Crude oilc
Natural gas liquids
Gas

2015

Crude oilc
Natural gas liquids
Gas

2014

Crude oilc
Natural gas liquids
Gas

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
Americab

Russia

Rest of
Asia

42.80
25.70
4.50

52.42
30.66
7.83

96.02
58.11
8.13

–
–
–

40.16
20.16
4.19

50.68
28.20
6.49

97.77
52.97
8.22

50.71
–
5.16

–
–
–

39.65
14.71
1.90

49.84
14.80
2.10

93.66
32.28
3.80

–
–
–

26.11
–
–

26.71
–
–

–
–
–

45.64
21.40
1.72

53.19
27.66
2.67

96.85
41.62
4.65

48.88
34.51
4.21

54.24
13.17
4.35

73.87
15.75
4.73

40.83
21.30
3.89

49.09
31.94
4.40

93.99
53.67
5.92

–
–
–

39.29
–
3.39

49.33
–
5.35

97.07
–
6.28

41.52
32.70
5.71

50.64
36.69
7.35

94.04
65.70
11.20

–
–
–

36.36
n/af
1.39

12.92
–
6.11

44.78
n/af
1.48

16.87
–
7.56

84.19
n/af
2.18

14.70
–
12.83

–
–
–

Total
group
average

39.99
17.31
2.84

49.72
20.75
3.80

94.74
36.15
5.70

34.04
34.51
2.20

41.49
13.17
2.35

72.53
15.75
3.01

Average production cost per unit of productiong

$ per unit of production

Europe

North
America

South
America

Africa

Asia

Australasia

Rest of
Europe

Rest of
North
America

Russia

Rest of
Asia

14.80
22.95
44.67

–
–
–

13.72
13.80
18.85

10.41
–
–

10.20
11.84
14.22

21.79
43.56
–

4.21
5.44
5.43

9.34
11.02
13.37

–
–
–

7.08
11.22
16.24

–
–
–

10.66
12.10
11.28

–
–
–

2.46
2.60
3.82

3.67
4.59
4.34

2.62
2.88
3.92

–
–
–

Total
group
average

8.46
10.46
12.75

3.57
3.93
4.75

Subsidiaries

2016
2015d
2014d

Equity-accounted entities

2016
2015
2014

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.
b All of the production from Canada in Subsidiaries is bitumen.
c Includes condensate.
d Production volume recognition methodology for our Technical Service Contract arrangement in Iraq has been simplified to exclude the impact of oil price movements on lifting imbalances. A

minor adjustment has been made to comparative periods. There is no impact on the financial results.

e In certain countries 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.

f Crude oil includes natural gas liquids.
g Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.

256

BP Annual Report and Form 20-F 2016

Environmental expenditure

Environmental expenditure relating to the

Gulf of Mexico oil spill

Operating expenditure
Capital expenditure
Clean-ups
Additions to environmental remediation

provision

Increase (decrease) in decommissioning

2016

2015

–
487
564
27

5,452
521
733
34

262

305

$ million

2014

190
624
590
33

371

provision

(804)

972

2,216

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,
treatment or elimination of air and water emissions and solid waste is
often not incurred as a separately identifiable transaction. Instead, it
forms part of a larger transaction that includes, for example, normal
operations and 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 $487 million in 2016 (2015
$521 million) showed an overall decrease of 7% which was due to
price deflations and reduced environmental expenditure following the
divestment of our petrochemicals site in Decatur, partially offset by a
higher level of activity at Whiting refinery.

Environmental capital expenditure in 2016 was lower overall than in
2015, largely due to lower spend as a result of the completion of the
installation of a dissolved nitrogen floatation unit at Whiting refinery’s
wastewater treatment plant in the previous year. 2015 also included
higher spend relating to the upgrade to our latest generation PTA
technology at some of our petrochemicals sites. These reductions
were partially offset by an increased spend on a new LPG refrigeration
plant for the North Sea forties pipeline system.

Clean-up costs decreased to $27 million in 2016 compared with
$34 million in 2015, primarily due to decreased contractual rates,
currency devaluation in certain regions and overall cost reductions.

In addition to operating and capital expenditure, we also establish
provisions for future environmental remediation work. 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 was similar to
prior years and also reflects scope reassessments of the remediation
plans of a number of our sites in the US and Canada. The charge for
environmental remediation provisions in 2016 included $7 million in
respect of provisions for new sites (2015 $6 million and 2014
$13 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 2016 the net decrease in the decommissioning provision occurred
as a result of detailed reviews of expected future costs, partially offset
by increases to the asset base. The increases in 2015 and 2014 were
driven by detailed reviews of expected future costs and increases to
the asset base.

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 Financial statements – Note 22.

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 more than 70 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.

Upstream contractual and regulatory framework

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 (alone or with other
contracting companies) 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

* See Glossary.

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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 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 and by 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
reservoirs 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.

Greenhouse gas regulation

Agreement commits all parties to submit Nationally Determined
Contributions (NDCs) (i.e. pledges or plans of climate action) and
pursue domestic measures aimed at achieving the objectives of their
NDCs. Developed country NDCs should include absolute emission
reduction targets, and developing countries are encouraged to move
over time towards them. The Paris Agreement places binding
commitments on countries to report on their emissions and progress
made on their NDCs and to undergo international review of collective
progress. It also requires countries to submit revised NDCs every five
years, which are expected to be more ambitious with each revision.
Global assessments of progress will occur every five years, starting in
2023. In the decision adopting the Paris Agreement, an earlier
commitment by developed countries to mobilize $100 billion a year by
2020 was extended through 2025, with a further goal with a floor of
$100 billion to be set before 2025.

The United Nations climate change conference in Marrakech (COP22),
held in November 2016, agreed a deadline of 2018 for countries to
agree on the guidelines and rules that are needed to support
implementation of the Paris Agreement.

More stringent national and regional 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:

United States

In the US, the Obama administration adopted its Climate Action Plan in
2013 and had been using existing statutory authority to implement that
plan, including the Clean Air Act (CAA) and the Mineral Leasing Act
(MLA). On 28 March 2017 the Trump administration issued an
Executive Order (EO) rescinding major elements of the Climate Action
Plan, and instructing the Environmental Protection Agency (EPA) to
review and then commence the process of suspending, revising or
rescinding certain regulations, including the Clean Power Plan and the
EPA new source methane rule. The EO also instructs the Department
of Interior to review and possibly suspend, revise or rescind the Bureau
of Land Management (BLM) methane rule.

• GHG emissions are currently regulated in a number of ways under
the CAA, though some of these regulations may be suspended,
revised or rescinded as noted above.

– Stricter GHG regulations, stricter limits on sulphur in fuels,

recent emissions regulations in the refinery sector and a revised
lower ambient air quality standard for ozone, finalized by the
EPA in October 2015, will affect our US operations in the future.

– EPA regulations aimed at methane emissions are in place for
new and modified sources and the BLM has issued methane
regulations for existing sites located on federal lands.
It is possible that EPA will be required by statute to propose
regulations on existing sources of methane from onshore oil
and natural gas sector activities, unless the EPA new source
methane rule is rescinded.

–

– States may also have separate, stricter air emission laws in

addition to the CAA and in some cases are considering joining
carbon trading markets (e.g. California).

In December 2015, nearly 200 nations at the United Nations climate
change conference in Paris (COP21) agreed the Paris Agreement, for
implementation post-2020. The agreement came into force on
4 November 2016. For the first time this agreement applies to all
countries, both developing and developed, although in some instances
allowances or flexibilities are provided for developing nations. The
Paris Agreement aims to hold global average temperature rise to well
below 2°C above pre-industrial levels and to pursue efforts to limit
temperature rise to 1.5°C above pre-industrial levels. There is no
quantitative long-term emissions goal. However, countries aim to
reach global peaking of greenhouse gas (GHG) emissions as soon as
possible and to undertake rapid reductions thereafter, so as to achieve
a balance between human caused emissions by sources and removals
by sinks of GHGs in the second half of this century. The Paris

• The Energy Policy Act of 2005 and the Energy Independence and

Security Act of 2007 impose a renewable fuel mandate (the federal
Renewable Fuel Standard) as well as state initiatives that impose
low GHG emissions thresholds for transportation fuels (currently
adopted in California, through the California Low Carbon Fuel
Standard and Oregon).

• EPA regulations impose light, medium and heavy duty vehicle

emissions standards for GHGs and permitting requirements for
certain large GHG stationary emission sources. The EPA and the
National Highway Traffic Safety Administration are considering a
proposed rulemaking to extend and tighten GHG emission and fuel
efficiency standards until 2027. This will have an impact on BP’s
product mix and overall demand. The Trump administration has
announced that it will reconsider these standards.

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• 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
GHG products are required to report product volumes and notional
GHG emissions as if these products were fully combusted.

• In October 2015 the EPA published its final Clean Power Plan (CPP)
which was an important element of the Obama administration’s
Climate Action Plan. Legal challenges have been filed and the US
Supreme Court has stayed the rule until the litigation is resolved,
which is not expected until later in 2017 or 2018. The US Appellate
Court heard arguments on the case in September 2016 and it is
anticipated that its decision will be the subject of a request for
review by the US Supreme Court. These rules are important due to
potential impacts on electricity prices, reliability of electricity
supply, precedents for similar rules targeting other sectors and
potential impacts on combined heat and power installations. As
noted above, the Trump administration has instructed the EPA to
review certain regulations including the CPP and may decline to
defend certain legal challenges to the CPP in court.

• In January 2015 the Obama administration announced plans to reduce
methane emissions from the oil and gas sector by 40-45% from 2012
levels by 2025. In June 2016 the EPA finalized rules aimed at limiting
methane emissions from new and modified sources in the oil and
natural gas sector in the US. The EPA has announced its intent to
adopt a regulation that would apply to existing sources in the sector.
In January 2017 the BLM’s methane rule, aimed at limiting methane
emissions on federal lands from new, modified and existing sources
in the oil and gas sector, came into effect. These EPA and BLM rules
will require further actions by our US upstream businesses to manage
methane emissions. As above, the Trump administration’s March
2017 EO instructs the Department of Interior to review and possibly
suspend, revise or rescind the BLM and EPA methane rules.

• A number of additional state and regional initiatives in the US will
affect our operations. The California cap and trade programme
started in January 2012 and expanded to cover emissions from
transportation fuels in 2015. The state of Washington recently
adopted a carbon cap rule that is planned to begin in 2017.

European Union
• 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 was adopted that includes: a collective national reduction
target for emissions not covered by the EU Emissions Trading System
(EU ETS) Directive; 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 under
the Renewable Energy Directive (a revision to which was proposed by
the European Commission in November 2016); a legal framework to
promote carbon capture and storage (CCS); and a revised EU ETS
Phase 3. EU ETS revisions included 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 (including the petrochemicals sector) and gases; no free
allocation for electricity generation (including that which is self-
generated off-shore) or production, but sector benchmarked free
allocation for all other installations, with sharply declining allocation for
sectors deemed not exposed to carbon leakage. EU ETS revisions
also included the adoption of a Market Stability Reserve to adjust the
supply of auctioned allowances. This will take effect in 2019 and could
potentially lead to higher carbon costs. EU Energy efficiency policy is
currently implemented via national energy efficiency action plans and
the Energy Efficiency Directive adopted in 2012.

• 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.
• In October 2014 the EU also agreed to the 2030 Climate and

Energy Policy framework 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. While
the European Commission has made legislative proposals,

including proposed amended targets, specific EU legislation and
agreements required to achieve these goals are still under
discussion in the European Council and European Parliament.
• European regulations also establish passenger car performance
standards for CO2 tailpipe emissions (European Regulation (EC)
No 443/2009). From 2020 onwards, the European passenger fleet
emissions target is 95 grams of CO2 per kilometre. This target will
be achieved by manufacturing fuel efficient vehicles and vehicles
using alternative, low carbon fuels such as hydrogen and
electricity. In addition, vehicle emission test cycles and vehicle
type approval procedures are being updated to improve accuracy of
emission and efficiency measurements. Consequently, product mix
and overall levels of demand will be impacted.

• European vehicle CO2 emission regulations also impact the fuel

efficiency of vans. By 2020, the EU fleet of newly registered vans
must meet a target of 147 grams of CO2 per kilometre, which is
19% below the 2012 fleet average.

• In addition, the Energy Efficiency Directive (EED), Industrial Emissions
Directive (IED) 2010, Medium Combustion Plants Directive (MCPD)
2015 and EU regulation on ozone depleting substances 2009 (ODS
Regulation) referenced below under ‘Other environmental regulation’
will also directly or indirectly require reductions in GHG emissions.

Other
• Canada’s highest emitting province, Alberta, has regulations targeting
large final emitters (sites with over 100,000 tonnes of carbon dioxide
equivalent per annum) with intensity targets of 2% improvement per
year up to 20%. Compliance is possible via direct reductions, the
purchase of offsets or the payment of C$20/tonne to a technology
fund which will escalate to C$30/tonne in 2017. In addition, a new
policy direction was announced by the Alberta government including
an economy-wide price of carbon that covers emissions not in the
scope of the existing regulations for large final emitters (C$20/tonne in
2017; C$30/tonne in 2018 then escalating in real terms), targeted
changes to electricity generation sources, a limit on overall oil sands
emissions, and sector specific performance standards (currently being
developed) to determine the volume of emissions subject to charges,
or use of other compliance mechanisms, including offsets. The
Canadian federal government has announced a number of climate
change policy goals including a national carbon price starting at
C$10/tonne and escalating to C$50/tonne by 2022 (or equivalent
system for provinces with cap-and-trade systems), with
implementation of the price, use of any funds generated and outcome
reporting being managed by each province.

• In the November 2014 US-China joint announcement on climate

change addressing post-2020 actions, which was reaffirmed by the
countries’ respective presidents in September 2015 and March
2016, 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 are likely to
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. In the March
2016 US-China joint presidential statement both countries agreed
to ratify the Paris Agreement including submission of their
domestic reduction commitments detailed above.

• China is operating emission trading pilot programmes in five cities
and two provinces. Two of BP’s joint venture* companies in China
are participating in these schemes. A nationwide carbon emissions
trading market is expected to be launched in 2017 which will
supersede the above seven pilot programmes. It is also proposed
to carry out pilot programmes on compensation for and trading of
energy quotas in four provinces in 2017 which may be expanded to
nationwide in or after 2020.

• China has also adopted more stringent vehicle tailpipe emission

standards and vehicle efficiency standards to address air pollution
and GHG emissions. These standards will have an impact on
transportation fuel product mix and overall demand.

For information on the steps that BP is taking in relation to climate
change issues and for details of BP’s GHG reporting, see
Sustainability – Climate change on page 43.

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Other environmental regulation
Current and proposed fuel and product specifications, emission
controls (including control of vehicle emissions), 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 or properties. 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 22 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 257.
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:
United States
• Since taking office in January, the Trump administration has issued
a number of EOs intended to reform the federal permitting and
rulemaking processes to reduce regulatory burdens placed on
manufacturing generally and the energy industry specifically. These
EOs immediately rescind certain policies and procedures and order
the commencement of a broad process to identify other actions
that may be taken to further reduce these regulatory requirements.
It is not clear how much or how quickly these regulatory
requirements will be reduced given statutory and rulemaking
constraints and the likely opposition to some of these initiatives.

• The National Environmental Policy Act (NEPA) requires that the

federal government gives proper consideration to the environment
prior to undertaking any major federal action that significantly
affects the environment, which includes the issuance of federal
permits. The environmental reviews required by NEPA can delay
projects. In August 2016, the White House Council on
Environmental Quality issued guidance to federal agencies
requiring that climate impact be considered under NEPA. These
requirements could further delay projects that require federal
action such as exploration and production plans. States law
analogues to NEPA could also limit or delay our projects.

• The CAA regulates air emissions, permitting, fuel specifications and
other aspects of our production, distribution and marketing activities.

• 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 the limitations discussed above under ‘Greenhouse
gas regulation’. California also imposes Low Emission Vehicle (LEV)
and Zero Emission Vehicle (ZEV) standards on vehicle manufacturers.
These regulations will have an impact on fuel demand and product
mix in California and those states adopting LEV and ZEV 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

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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 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 CERCLA, the Oil
Pollution Act of 1990 (OPA 90) (discussed below) and other federal
and state laws. CERCLA also requires notification of releases of
hazardous substances to national, state and local government
agencies, as applicable. In addition, the Emergency Planning and
Community Right-to-Know Act requires notification of releases of
designated quantities of certain listed hazardous substances to state
and local government agencies, as applicable.

• The Toxic Substances Control Act (TSCA) regulates BP’s

manufacture, import, export, sale and use of chemical substances
and products. In June 2016, the US enacted legislation to
modernize and reform TSCA (the Frank R. Lautenberg Chemical
Safety for the 21st Century Act). The EPA has begun to develop
proposed rules, processes and guidance to implement the reforms.
Key components of the reform legislation include: (1) a reset of the
TSCA chemical inventory, (2) new chemical management
prioritization efforts expanding risk assessment and risk
management practices, (3) new confidentiality provisions, and
(4) new authority for the EPA to impose a fee structure.

• The Occupational Safety and Health Act imposes workplace safety
and health requirements on BP operations along with significant
process safety management obligations, requiring continuous
evaluation and improvement of operational practices to enhance
safety and reduce workplace emissions at gas processing, refining
and other regulated facilities. In 2016 the Obama administration
announced that the US Occupational Safety and Health
Administration (OSHA) would implement a ‘National Emphasis
Program’ set of inspections aimed at refineries and petrochemical
facilities. The Trump administration has not made any
announcement regarding its intentions for this program.
• 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 and the DOT Hazardous

Materials (HAZMAT) regulations impose security compliance
regulations on certain BP facilities.

• OPA 90 is implemented through regulations issued by the 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.
• The Outer Continental Shelf Land Act, the MLA and other statutes
give the Department of Interior (DOI) and the BLM authority to
regulate operations and air emissions on offshore and onshore
operations on federal lands subject to DOI authority. New stricter
regulations on operational practices, equipment and testing have
been imposed on our operations in the Gulf of Mexico and
elsewhere following the Deepwater Horizon oil spill. In addition, in
2016 the DOI proposed to regulate methane emissions from
onshore oil and natural gas sector operations.

• The Endangered Species Act and Marine Mammal Protection Act
protect certain species from adverse human impacts. The species
and their habitat may be protected thereby restricting operations or
development at certain times and in certain places. With an
increasing number of species being protected, we have increasing
restrictions on our activities.

European Union

• The 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 has been implemented in the UK by the
Energy Savings Opportunity Scheme Regulations 2014, which
affects our offshore and onshore assets. The ISO50001 standard is
being implemented by organizations in some EU states to meet
some elements of the Energy Efficiency Directive. A revision to the
EED was proposed by the European Commission in November
2016, which includes a new energy efficiency target for 2030.

• The 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. 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 BAT
Conclusions for the refining sector, for combustion as well as
petrochemicals production. These may result in requirements for
BP to further reduce its emissions, particularly its air and water
emissions.

• The MCPD came into force on 18 December 2015 and must be

implemented by member states by 19 December 2017. It applies
to air emissions of sulphur dioxide (SO2), nitrogen oxides (NOx) and
particulates from the combustion of fuels in plants with a rated
thermal input between one and 50MW. It also includes
requirements to monitor emissions of carbon monoxide (CO) from
such plant. Its requirements will be phased in – the emission limit
values set in the Directive will apply from 20 December 2018 for
new plants and by 2025 or 2030 for existing plants, depending on
their size.

• The National Emission Ceiling Directive 2001 has been revised to
introduce stricter emissions limits from 2030, with new indicative
national targets applying from 2025. Formal adoption of the revised
Directive is pending.

• The ODS Regulation requires BP to reduce the use of ozone

depleting substances (ODSs) and phase out use of certain ODSs.
BP continues to replace ODSs 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
GHGs with high global warming potential (the F-gas Regulations)
came into force on 1 January 2015. The F-gas Regulations require a
phase-out of certain hydrofluorocarbons, based on global warming
potential.

• The EU Registration, Evaluation Authorization and Restriction 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
manufacturing or trading/import operations in the EU. Since coming
into force in 2007, REACH implementation has followed a phase-in
schedule defined by the EU. The final phase-in implementation
deadline requires registration of substances manufactured or
imported in the tonnage-band of 1-100 tonnes per annum per legal
entity by 31 May 2018. BP is in the process of preparing and
submitting registration dossiers to meet this final REACH
implementation milestone. For higher tonnage-band substances,
BP maintains compliance by checking whether imports are covered
by the registrations of non-EU suppliers’ representatives, preparing
and submitting registration dossiers to cover new manufactured
and imported substances, and updating previously submitted
registrations as required. Some substances registered previously,
including substances supplied to us by third parties for our use, are
now subject to evaluation and review for potential authorization or
restriction procedures, and possible banning, by the European
Chemicals Agency and EU member state authorities.

• The EU Offshore Safety Directive was adopted in 2013. 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. The Directive has been
implemented in the UK primarily through the Offshore Installations
(Offshore Safety Directive) (Safety Case etc.) Regulations 2015.
• The Water Framework Directive (WFD) published in 2000 aims to
protect the quantity and quality of ground and surface waters of
the EU member states. The ongoing implementation of the WFD
and the related Environmental Quality Standards Directive 2008 as
well as the planned revision of the WFD in 2019 is likely to require
additional compliance efforts and increased costs for managing
freshwater withdrawals and discharges from BP’s EU operations.

Regulations governing the discharge of treated water have also been
developed in countries outside of the US and EU. This includes
regulations in Trinidad and Angola. In Trinidad, BP has been working
with the regulators to apply water discharge rules arising from the
Certificate of Environmental Clearance (CEC) Regulations 2001 and
associated Water Pollution Rules 2007. In Angola, BP has been
upgrading produced water treatment systems to meet revised oil in

water limits for produced water discharge under Executive Decree
ED 97-14 (superseded ED 12/05 on 1 January 2016).

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:

• Liability and spill prevention and planning requirements governing,
among others, tankers, barges and offshore facilities are imposed
by OPA in US waters. 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 (IMO), including the International
Convention on Civil Liability for Oil Pollution Damage, the
International Convention for the Prevention of Pollution from Ships
(MARPOL), 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 at 31 December 2016, as the required
minimum number of contracting states had not been achieved, the
HNS Convention had not entered into force.

• A global sulphur cap of 0.5% will apply to marine fuel from January
2020 under MARPOL. In order to comply, ships will either need to
consume low sulphur marine fuels or implement approved
abatement technology to enable them to meet the low sulphur
emissions requirements whilst continuing to use higher sulphur
fuel. This new global cap will not alter the lower limits that apply in
the sulphur oxides Emissions Control Areas established by the
IMO.

• Ships will be required to have ballast water treatment systems in

place within the time frame prescribed by the International
Convention for the Control and Management of Ships’ Ballast
Water and Sediments 2004, which is due to enter into force in
September 2017.

To meet its financial responsibility requirements, BP Shipping
maintains marine pollution liability 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.

Legal proceedings
Proceedings relating to the Deepwater Horizon oil
spill
Introduction

BP Exploration & Production Inc. (BPXP) was lease operator of
Mississippi Canyon, Block 252 in the Gulf of Mexico (Macondo),
where the semi-submersible rig Deepwater Horizon was deployed at
the time of the 20 April 2010 explosions and fire and resulting oil spill
(the Incident). Lawsuits and claims arising from the Incident have
generally been brought in US federal and state courts.

Many of the lawsuits in federal court relating to the Incident were
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 Employee
Retirement Income Security Act (ERISA) cases (MDL 2185) and
another in federal district court in New Orleans for the remaining
cases (MDL 2179). A Plaintiffs’ Steering Committee (PSC) was
established to act on behalf of individual and business plaintiffs in
MDL 2179. These proceedings, and other material lawsuits and claims
arising from the Incident, are discussed below.

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Federal and state claims

MDL 2179 – Department of Justice (DoJ) Action, State and local
authority claims consolidated into MDL 2179 and Trial of Liability,
Limitation, Exoneration and Fault Allocation
The US filed a civil complaint in MDL 2179 against BPXP and others
on 15 December 2010 (the DoJ Action). The complaint sought an
order finding liability under the Oil Pollution Act of 1990 (OPA 90) for
natural resources damages and civil penalties under the Clean Water
Act (CWA).

Between 2010 and 2013, the states of Alabama, Florida, Louisiana,
Mississippi and Texas (the five Gulf Coast states) filed lawsuits
seeking declaratory and injunctive relief, and punitive damages, as a
result of the Incident. Each of these actions was consolidated with
MDL 2179.

A Trial of Liability, Limitation, Exoneration and Fault Allocation (the
Trial) in MDL 2179 commenced on 25 February 2013. The district
court issued its ruling on the first phase of the Trial in September
2014. BPXP, BP America Production Company (BPAPC) and various
other parties were each found 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 CWA, the
district court found that the discharge of oil was the result of BPXP’s
gross negligence and wilful misconduct and that BPXP was therefore
subject to enhanced civil penalties.

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 and were therefore subject to a CWA penalty.
In addition, the district court found that BP was not grossly negligent
in its source control efforts. For further details of the Trial, see ‘Legal
proceedings’ in BP Annual Report and Form 20-F 2014.

BP appealed both rulings but following the settlement between the
US and BPXP (discussed below), on 19 October 2016 BP and the
PSC filed a joint stipulation to dismiss the appeals. Both appeals have
now been dismissed but BP could appeal the rulings in the future if a
claimant was successful in an action against BP that includes a final
judgment that incorporates the district court’s rulings on these trial
phases.

The penalty phase of the Trial involved consideration of the amount of
CWA civil penalties owed to the United States, and concluded in
February 2015. No decision was entered by the district court with
respect to BPXP following this phase of the trial in light of the
subsequent settlement between the US and BPXP.

Consent Decree and Settlement Agreement
On 2 July 2015, BP announced that BPXP had executed agreements
in principle with the United States federal government and the five
Gulf Coast states to settle all federal and state claims arising from the
Incident. In addition, BPXP also settled the claims made by more than
400 local government entities.

On 5 October 2015, the United States lodged with the district court in
MDL 2179 a proposed Consent Decree between the United States,
the five Gulf Coast states and BP to fully and finally resolve any and all
natural resource damages claims of the United States, the five Gulf
Coast states and their respective natural resource trustees and all
CWA penalty claims, and certain other claims of the United States and
the five Gulf Coast states. Concurrently, BP entered into a definitive
Settlement Agreement with the five Gulf Coast states (Settlement
Agreement) with respect to state claims for economic, property and
other losses. On 4 April 2016 (the Effective Date), the court entered
the Consent Decree and also entered a final judgment in the DoJ
Action on the terms set forth in the Consent Decree, at which time
the Consent Decree and Settlement Agreement became effective.

For further details of the Consent Decree and Settlement Agreement,
including details of the principal payments, see ‘Legal proceedings’ in
BP Annual Report and Form 20-F 2015.

OPA Test Case Proceedings
A number of lawsuits were brought, primarily by business claimants,
under OPA 90 in relation to the 2010 federal deepwater drilling
moratoria. Six test cases, consolidated with MDL 2179, were
scheduled to address certain OPA 90 liability questions focusing on,

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among other issues, whether the plaintiffs’ alleged losses tied to the
moratoria and whether federal permit delays are compensable. On
10 March 2016, the court ruled that BPXP is not, as a ‘Responsible
Party’ under OPA 90, liable for economic losses that resulted from the
2010 deepwater drilling moratoria. The court’s order dismissed the
plaintiffs’ claims with prejudice. On 19 March 2016, the plaintiffs
appealed the court’s ruling to the Fifth Circuit. Subsequently, BPXP
settled the claims of each of the test case plaintiffs and their cases
and the pending appeals to the Fifth Circuit have been dismissed.

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. BP completed the final
payment for the $1 billion early restoration funds in April 2016.

Under the Consent Decree, Trustees will continue to implement these
early restoration projects as part of the final settlement of all US and
state claims for natural resource damages.

PSC settlements

PSC settlements – Economic and Property Damages Settlement
Agreement
The Economic and Property Damages Settlement resolved certain
economic and property damage claims, and included a $2.3 billion BP
commitment to help resolve economic loss claims related to the Gulf
seafood industry (the Seafood Compensation Program) and a
$57-million fund to support advertising to promote Gulf Coast tourism.
It also resolved 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 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 final deadline for filing all claims
other than those that fall into the Seafood Compensation Program
was 8 June 2015.

Following numerous court decisions on 31 March 2015, the court
denied the PSC’s motion seeking to alter or amend a revised policy,
addressing the matching of revenue and expenses for business
economic loss claims, which requires 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 23 April 2015, the PSC appealed this decision to the Fifth Circuit.
On 18 December 2015, the PSC and BP entered into a joint stipulation
to stay this appeal pending resolution of certain issues in the district
court in New Orleans. On 8 January 2016, the Fifth Circuit granted the
joint stipulation and stayed the appeal and in further orders extended
the stay until 7 September 2016. That stay has now expired and the
oral argument took place on 8 March 2017.

For more information about BP’s current estimate of the total cost of
the Economic and Property Damages Settlement, see Financial
statements – Note 2.

PSC settlements – Medical Benefits Class Action Settlement
The Medical Benefits Class Action Settlement (Medical Settlement)
involves payments to qualifying class members based on a matrix for
certain Specified Physical Conditions (SPCs), as well as a 21-year
Periodic Medical Consultation Program (PMCP) for qualifying class
members, and also includes provisions regarding class members
pursuing claims for later-manifested physical conditions (LMPCs).

The deadline for submitting SPC and PMCP claims was 12 February
2015. The Medical Claims Administrator has reported the total number
of claims submitted is approximately 37,250. As of 3 March 2017,
approximately 22,300 SPC claims, totalling approximately
$64.2 million, have been approved for compensation. In addition,
approximately 26,200 claimants have been determined eligible for the
PMCP and there are six pending lawsuits brought by class members
claiming LMPCs.

For further details of the Medical Settlement, see ‘Legal proceedings’
in BP Annual Report and Form 20-F 2015.

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 20 May 2014, the court 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. The parties appealed the district
court’s class certification decisions and on 8 September 2015, the
Fifth Circuit affirmed both of the district court’s decisions. On 2 May
2016, the Supreme Court denied the pre-explosion ADS purchasers’
final petition.

Following various legal proceedings, on 2 June 2016, BP announced
that it had agreed with plaintiffs’ representatives to settle the class
claims of the post-explosion ADS purchasers for the amount of
$175 million, payable during 2017, subject to approval by the court.
The parties filed the settlement agreement and other papers in
support of approval with the court on 15 September 2016 and a class
notice was issued on 14 November 2016. On 13 February 2017 the
court granted final approval of the class settlement.

Individual securities litigation

From April 2012 to April 2016, 38 cases were filed in state and federal
courts by pension funds, investment funds and advisers against BP
entities and several current and former officers and directors seeking
damages for alleged losses those funds suffered because of their
purchases and/or holdings of BP ordinary shares and, in certain cases,
ADSs. The funds assert claims under English law and, for plaintiffs
purchasing ADSs, federal securities law, and seek damages for
alleged losses that those funds suffered because of their purchases
and holdings of BP ordinary shares and/or ADSs. All of the cases, with
the exception of one case that has been stayed, have been transferred
to MDL 2185. On 4 January 2016, the district court dismissed two of
those cases and some of the claims of a third case. Plaintiffs in the
two dismissed cases filed amended complaints on 19 January 2016.
On 8 July 2016, the district court granted leave for these plaintiffs to
file amended complaints. On 28 September 2016, defendants filed a
motion to dismiss certain claims against certain defendants in 20 of
the individual securities cases and briefing is expected to be
completed on that motion in April 2017.

Canadian class action

On 15 November 2012, a plaintiff re-filed a statement of claim against
BP in Ontario, Canada, 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. On 14 August 2014, the Ontario Court of Appeal held 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. Following an
unsuccessful claim by the plaintiff in Texas federal court, on 26 February
2016, the plaintiff filed a motion in the Court of Appeal for Ontario to lift
the stay on the Canadian action, which was granted on 29 July 2016. On
19 January 2017 the Supreme Court of Canada denied BP’s motion for
leave to appeal from the Court of Appeal’s decision.

ERISA

On 15 January 2015, in an ERISA case related to BP share funds in
several employee benefit savings plans, the federal district court in
Houston allowed the plaintiffs to amend their complaint to allege
some of their proposed claims against certain defendants. On
26 September 2016, the Fifth Circuit reversed the decision of the
district court, holding that the amended complaint is insufficient to
state a claim against defendants, that the district court erred in
granting the plaintiffs’ motion to amend, and remanding the case to

the district court for further proceedings. On 22 November 2016,
plaintiffs filed a motion to file an amended complaint, and on 8 March
2017, that motion was denied.

Other Deepwater Horizon oil spill related claims

Other civil complaints – economic loss

On 29 March 2016, the district court in MDL 2179 issued an order
dismissing in its entirety the master complaint raising claims for
economic loss by private plaintiffs (the March 2016 Order). The court
ordered that all private plaintiffs who had filed a timely claim for
economic loss against BP in MDL 2179 and had not released those
claims must file and serve on BP a sworn statement disclosing
information regarding their claims by 2 May 2016. In addition, the
court required plaintiffs who had not filed an individual complaint
(defined as a complaint not joined in by other plaintiffs) against BP to
file a new individual complaint by 2 May 2016. Plaintiffs who failed to
comply with the sworn statement requirement or the new individual
complaint requirement by 2 May 2016 (which deadline was extended
by 14 days for some of the plaintiffs) were to have their claims
deemed dismissed with prejudice without further notice. The court
issued a supplemental order confirming that all new complaints filed
would be stayed until further direction by the court.

On 7 June 2016, the court issued an order requiring private plaintiffs
who had not complied with the March 2016 Order to show cause in
writing by 28 June 2016 why their claims should not be dismissed
with prejudice. The court also dismissed all joinders by plaintiffs in the
master complaint for private plaintiff economic loss and property
damages claims. On 14 July 2016 the federal district court issued an
order listing those 962 plaintiffs who complied with the March 2016
Order and those plaintiffs whose compliance with the March 2016
Order remained to be determined by the court. The court dismissed
with prejudice any remaining claims by private plaintiffs for economic
loss and property damage. Accordingly the vast majority of economic
loss and property damage claims from individuals and businesses that
either opted out of the 2012 settlement with the Plaintiffs’ Steering
Committee and/or were excluded from that settlement have either
been resolved or dismissed.

On 16 December 2016, the district court issued a ruling on the show
cause submissions filed by plaintiffs whose compliance with the
March 2016 Order remained to be determined by the court. The
court’s ruling held another 61 plaintiffs to be noncompliant with the
March 2016 Order and dismissed their claims. It found an additional
57 plaintiffs to have complied with the March 2016 Order and to be
subject to further proceedings in MDL 2179.

On 22 February 2017 the district court in MDL 2179 ordered that any
remaining plaintiffs who wish to pursue a general maritime law claim
must file and serve on BP a sworn statement as to their proprietary
interest in property physically damaged by oil, and whether they
worked as commercial fishermen, by 5 April 2017.

Other civil complaints – personal injury
On 22 February 2017 the district court in MDL 2179 issued an order
dismissing in its entirety the master complaint raising claims for post-
explosion clean-up, medical monitoring and personal injury claims
occurring after the explosion and fire of 20 April 2010. The court
ordered that all plaintiffs who had filed a timely claim for such personal
injury cases against BP in MDL 2179 and had not released those
claims must file and serve on BP a sworn statement disclosing
information regarding their claims by 12 April 2017. In addition, the
court required plaintiffs who had not filed an individual complaint
(defined as a complaint not joined in by other plaintiffs) against BP to
file a new individual complaint by 12 April 2017. Plaintiffs who failed to
comply with the sworn statement requirement or the new individual
complaint requirement by 12 April 2017 were to have their claims
deemed dismissed with prejudice without further notice.

Non-US government lawsuits

On 5 April 2011, the Mexican 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. This was followed by a suit against BP
which was transferred to MDL 2179 where it remains pending.

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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.

On 18 October 2012, before a Mexican Federal District Court located
in Mexico City, a class action complaint was filed against BPXP,
BPAPC and other BP subsidiaries. BPXP has since been dismissed.
The plaintiffs, who allegedly are fishermen, are seeking, among other
things, compensatory damages for the class members who allegedly
suffered economic losses, as well as an order requiring BP to
remediate environmental damage resulting from the Incident, to
provide funding for the preservation of the environment and to
conduct environmental impact studies in the Gulf of Mexico for the
next 10 years. BP has not been formally served with the action.
However, after learning that the Mexican Federal District Court issued
a resolution in the class action that impacted BP’s rights, BP filed a
constitutional challenge (amparo) in Mexico asserting that BP has
never been formally served with process in the class action. This
amparo was denied and is now on appeal.

On 3 December 2015 and 29 March 2016, Acciones Colectivas de
Sinaloa (ACS) filed two class actions (which have since been
consolidated) in a Mexican Federal District Court on behalf of several
Mexican states. In these class actions, plaintiffs seek an order
requiring the BP defendants to repair the damage to the Gulf of
Mexico, to pay penalties, and to compensate plaintiffs for damage to
property, to health and for economic loss. BP has not been formally
served with the action.

False Claims Act actions

On 17 December 2012, the court ordered one complaint to be
unsealed that had been filed in the US District Court for the Eastern
District of Louisiana by an individual under the Qui Tam (whistle
blower) provisions of the False Claims Act (FCA). 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 the court subsequently stayed the action. Following the
Effective Date, under the terms of the Consent Decree, the
United States and Gulf states covenanted not to pursue claims against
BP under the FCA. On 3 February 2017 the plaintiff in the False Claims
Act case voluntarily dismissed the action.

US Department of Interior matters

On 12 October 2011, the US Department of the Interior Bureau of
Safety and Environmental Enforcement issued to BP, Transocean, and
Halliburton notification of Incidents of Noncompliance (INCs). The
notification issued to BP is for a number of alleged regulatory
violations concerning Macondo well operations. On 7 December 2011,
the Bureau of Safety and Environmental Enforcement issued to BP a
second INC for five alleged violations related to drilling and
abandonment operations at the Macondo well. BP filed an
administrative appeal with respect to the first and second INCs and
filed a joint stay of proceedings with the Department of Interior with
respect to both INCs. Pursuant to the Consent Decree with the United
States (see above), BP withdrew its appeals on 18 April 2016, and the
INCs have been fully and finally resolved.

Pending investigations and reports relating to the Deepwater
Horizon oil spill CSB investigation

On 13 April 2016, the US Chemical Safety and Hazard Investigation
Board (CSB) released the final two volumes of its four-volume report
on its investigation into the Incident. The final two volumes primarily
concern the role of the regulator in the oversight of the offshore
industry and organizational and cultural factors. They include proposed
recommendations to the US Department of Interior’s Bureau of Safety
and Environmental Enforcement, the American Petroleum Institute,
the Ocean Energy Safety Institute and the Sustainability Accounting
Standards Board.

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Other legal proceedings

FERC and CFTC matters

Following an investigation by the US Federal Energy Regulatory
Commission (FERC) and the US Commodity Futures Trading
Commission (CFTC) of several BP entities, the Administrative Law
Judge of the FERC ruled on 13 August 2015 that BP manipulated the
market by selling next-day, fixed price natural gas at Houston Ship
Channel in 2008 in order to suppress the Gas Daily index and benefit
its financial position. On 11 July 2016 the FERC issued an Order
affirming the initial decision and directing BP to pay a civil penalty of
$20.16 million and to disgorge $207,169 in unjust profits. On
10 August 2016, BP filed a request for rehearing with the FERC. BP
strongly disagrees with the FERC’s decision and will ultimately appeal
to the US Court of Appeals if necessary.

Investigations by the FERC and CFTC into BP’s trading activities
continue to be conducted from time to time.

CSB matters

In March 2007, the CSB issued a report on the March 2005 explosion
and fire at the BP Texas City refinery. The report contained
recommendations to the BP Texas City refinery and to the board of
directors of BP. On 25 May 2016, the CSB closed its last open
recommendation to BP. The CSB has now accepted that all of BP’s
responses to its recommendations have been satisfactorily addressed.

OSHA matters

On 8 March 2010, the US Occupational Safety and Health
Administration (OSHA) issued 65 citations to BP Products North
America Inc. (BP Products) and BP-Husky Refining LLC (BP-Husky) for
alleged violations of the Process Safety Management (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 outcome of a pre-trial settlement of a number of the
citations and a trial of the remainder was a reduction in the total
penalty in respect of the citations from the original amount of
approximately $3 million to $80,000. The OSH Review Commission
granted OSHA’s petition for review and briefing was completed in the
first half of 2014. Timing for the issuance of a decision by the Review
Commission is currently uncertain. Depending on the outcome of this
review, BP may also pay a penalty not to exceed $1 million in respect
of similar issues at the BP Texas City refinery.

Prudhoe Bay leak

In March and August 2006, oil leaked from oil transit pipelines
operated by BP Exploration (Alaska) Inc. (BPXA) at the Prudhoe Bay
unit on the North Slope of Alaska. On 12 May 2008, a BP p.l.c.
shareholder filed a consolidated complaint alleging violations of federal
securities law on behalf of a putative class of BP p.l.c. shareholders,
based on alleged misrepresentations concerning the integrity of the
Prudhoe Bay pipeline before its shutdown on 6 August 2006. On
7 December 2015, the complaint was dismissed with prejudice. On
5 January 2016, plaintiffs filed a notice of appeal of that decision to the
Ninth Circuit Court of Appeals, and briefing was completed on that
appeal on 14 October 2016.

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 an FCA lawsuit against
BP, alleging that BP violated federal regulations, and made false
statements in connection with its compliance with those regulations,
by failing to have necessary documentation for the Atlantis subsea
and other systems. BP is the operator and 56% interest owner of the
Atlantis unit, which is in production in the Gulf of Mexico. On
28 August 2014, the court entered final judgment in favour of BP and
on 14 March 2017, this was affirmed by the Fifth Circuit Court of
Appeals.

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. Trial is scheduled to
commence in the second half of 2017.

Scharfstein v. BP West Coast Products, LLC

A class action lawsuit was filed against BP West Coast Products, LLC in
Oregon State Court under the Oregon Unlawful Trade Practices Act on
behalf of customers who used a debit card at ARCO gasoline stations in
Oregon during the period 1 January 2011 to 30 August 2013, alleging
that ARCO sites in Oregon failed to provide sufficient notice of the 35
cents per transaction debit card fee. In January 2014, the jury rendered a
verdict against BP and awarded statutory damages of $200 per class
member. On 25 August 2015, the trial court determined the size of the
class to be slightly in excess of two million members. On 31 May 2016
the trial court entered a judgment for the amount of $417.3 million. On
1 June 2016 BP filed a notice of appeal. No provision has been made for
damages arising out of this class action.
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.

The US and the EU implemented temporary, limited and reversible
relief of certain sanctions related to Iran pursuant to a Joint Plan of
Action (JPOA) entered by Iran, China, France, Germany, Russia, the
UK and the US with effect from 20 January 2014 and in July 2015,
these countries, together with the EU, agreed the Joint
Comprehensive Plan of Action (JCPOA).

Following confirmation by the International Atomic Energy Agency on
16 January 2016 (Implementation Day) that Iran had fully implemented

the JCPOA measures necessary for sanctions relief, the European
Union and the United States lifted or suspended certain nuclear
related sanctions, with the EU lifting nuclear related primary sanctions
and the United States suspending nuclear related secondary
sanctions. Following Implementation Day, BP has considered and
developed possible business opportunities in relation to Iran, engaged
in discussions with Iranian government officials and other Iranian
nationals and attended conferences, and will continue to do so.

During the second half of 2016, BP Iran Limited leased and
refurbished an office in Tehran.

In December 2016, BP purchased condensate from National Iranian
Oil Company (NIOC). The condensate was loaded in Iran on
23 December 2016 and delivered to BP’s Rotterdam refinery on
15 January 2017. BP intends to continue to explore commercial
opportunities with NIOC (or its subsidiaries).

BP has a 50% interest in and operates the North Sea Rhum field
(Rhum). Iranian Oil Company (U.K.) Limited (IOC UK) holds a 50%
interest in Rhum. Production was suspended at Rhum in November
2010. Under a temporary management scheme, the UK government
assumed control of and managed IOC UK’s interest in the Rhum field,
thereby permitting Rhum operations to recommence in mid-October
2014 in accordance with applicable EU regulations and in compliance
with a licence from the US Office of Foreign Assets Control. Following
Implementation Day, the temporary management scheme ceased,
with control and management of IOC UK’s interest passing back to
IOC UK, and BP obtained an updated OFAC licence in relation to the
continued operation of Rhum on 29 September 2016.

BP has a 28.8% interest in and operates the Azerbaijan Shah Deniz
field (Shah Deniz) and a related gas pipeline entity, South Caucasus
Pipeline Company Limited (SCPC), and has a 23% non-operated
interest in a related gas marketing entity, Azerbaijan Gas Supply
Company Limited (AGSC). Naftiran Intertrade Co. Limited and NICO
SPV Limited (collectively, NICO) have a 10% non-operating interest in
each of Shah Deniz and SCPC and an 8% non-operating interest in
AGSC. Shah Deniz, SCPC and AGSC continue in operation as they
were excluded from the main operative provisions of the EU
regulations as well as from the application of the US sanctions, and fall
within the exception for certain natural gas projects under Section 603
of ITRA.
BP holds an interest in a non-BP operated Indian joint venture* and
sold produced crude oil to an Indian entity in which NICO holds a
minority, non-controlling stake.

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.

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.

BP has registered and paid required fees to maintain registrations of
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.

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During 2014 the US and the EU 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) was a 50:50
joint operation* with Rosneft, operated by BP, which held interests in
a number of refineries in Germany. These sanctions have had no
material adverse impact on BP or ROG. On 31 December 2016, the
previously-announced dissolution of ROG was completed.

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 Iran Threat Reduction and Syria
Human Rights Act of 2012 (ITRA) Section 219, with the following
possible exceptions:

• 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. The Rhum joint arrangement was originally formed in
1974. 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
2016, BP recorded gross revenues of $67.2 million related to its
interests in Rhum. BP had a net profit of $31.6 million for the year
ended 31 December 2016, including an impairment reversal of
$48.9 million in the third quarter of 2016. BP currently intends to
continue to hold its ownership stake in the Rhum joint arrangement
and act as operator.

• In December 2016, BP Singapore Pte. Limited (BPS) purchased a

shipment of South Pars condensate from NIOC, which was loaded
in Iran on 23 December 2016 and delivered to BP’s Rotterdam
refinery on 15 January 2017. BPS made a payment ($52 million
equivalent) in consideration for the condensate on 19 January
2017. Upon delivery, the condensate was comingled with other
products for refining, and therefore BP is unable to ascertain an
amount of gross revenue or gross profit attributable to it. BP
intends to continue to explore commercial opportunities with NIOC
(or its subsidiaries).

• BP Iran Limited leased and refurbished an office in Tehran during

2016. The office is used for administrative activities. In 2016, rental
tax payments associated with the Tehran office, with an aggregate
US dollar equivalent value of approximately $6,000, were paid from
a BP trust account held with Tadvin Co. to Iranian public entities.
No gross revenues or net profits were attributable to these
activities. BP intends to continue to maintain an office in Tehran.

• During 2016, certain BP employees visited Iran for the purpose of

meetings with Iranian government officials and other Iranian nationals
and attending conferences. Payments were made to Iranian public
entities for visas and taxes in relation to such visits with an aggregate
US dollar equivalent value of approximately $18,730. No gross
revenues or net profits were attributable to these activities, save
where otherwise disclosed, and BP intends to continue visits to Iran
in connection with various business opportunities.

• During 2016, BP Iran Limited entered into a number of

confidentiality agreements for the purpose of sharing information
with potential local Iranian partners. Two of these confidentiality
agreements are with exploration and production companies in
which the Iranian-state holds an interest. No gross revenues or net
profits were attributable to these activities. BP’s intention to
continue to explore commercial opportunities with one, both or
neither of these E&P companies is dependent upon the specific
outcome of the potential commercial opportunities with NIOC (or
its subsidiaries).

Material contracts
On 13 March 2014, BP, BP Exploration & Production Inc., 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

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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.

On 4 April 2016 the district court approved the Consent Decree
among BP Exploration & Production Inc., BP Corporation North
America Inc., BP p.l.c., the United States and the states of Alabama,
Florida, Louisiana, Mississippi and Texas (the Gulf states) which fully
and finally resolves any and all natural resource damages (NRD) claims
of the United States, the Gulf states, and their respective natural
resource trustees and all Clean Water Act (CWA) penalty claims, and
certain other claims of the United States and the Gulf states.

Concurrently, the definitive Settlement Agreement that BP entered
into with the Gulf states (Settlement Agreement) with respect to State
claims for economic, property and other losses became effective.

BP has filed the Consent Decree and the Settlement Agreement as
exhibits to its Annual Report on Form 20-F 2016 filed with the SEC.
For further details of the Consent Decree and the Settlement
Agreement, see Legal proceedings on page 261.
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 2016 and the group
percentage of ordinary share capital see Financial statements – Note
36. For information on significant joint ventures* and associates* of
the group see Financial statements – Notes 15 and 16.
Related-party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 15 and Note
16. 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 2016 to 16 March 2017.
Corporate governance practices
In the US, BP ADSs are listed on the New York Stock Exchange
(NYSE). The significant differences between BP’s corporate
governance practices as a UK company and those required by NYSE
listing standards for US companies are listed as follows:

Independence

BP has adopted a robust set of board governance principles, which
reflect the UK Corporate Governance Code and its principles-based
approach to corporate governance. As such, the way in which BP
makes determinations of directors’ independence differs from the
NYSE rules.

BP’s board governance principles require that all non-executive
directors be determined by the board to be ‘independent in character
and judgement and free from any business or other relationship which
could materially interfere with the exercise of their judgement’. The
BP board has determined that, in its judgement, all of the
non-executive directors are independent. In doing so, however, the
board did not explicitly take into consideration the independence
requirements outlined in the NYSE’s listing standards.

Committees

BP has a number of board committees that are broadly comparable in
purpose and composition to those required by NYSE rules for
domestic US companies. For instance, BP has a chairman’s (rather
than executive) committee, nomination (rather than nominating/
corporate governance) committee and remuneration (rather than
compensation) committee. BP also has an audit committee, which
NYSE rules require for both US companies and foreign private issuers.

These committees are composed solely of non-executive directors
whom the board has determined to be independent, in the manner
described above.

The BP board governance principles prescribe the composition, main
tasks and requirements of each of the committees (see the board
committee reports on pages 69-79). 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, reappointment 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 possesses 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 69). 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
members of the board, 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, group head of audit
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.
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 2016 fiscal year, management conducted an
assessment of the effectiveness of internal control over financial
reporting in accordance with the UK Financial Reporting Council’s
Guidance on Risk Management, Internal Control and Related Financial
and Business Reporting. Based on this assessment, management has
determined that BP’s internal control over financial reporting as of
31 December 2016 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 2016 has been audited by
Ernst & Young, an independent registered public accounting firm, as
stated in their report appearing on page 120 of BP Annual Report and
Form 20-F 2016.

Changes in internal control over financial reporting
There were no changes in the group’s internal control 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.

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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 2016.
During the year, a review of the terms and scope of the policy was
undertaken. The policy was renewed during 2016 and continued into
2017. 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.
Certain subsidiaries are trustees of the group’s pension schemes.
Each director of these subsidiaries* 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 How we
manage risk on page 47, Liquidity and capital resources on page 242
and Financial statements – Notes 28 and 29.

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 28.

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 Using technology on page 12.

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
Sustainability – Our people on page 46.

Employee share schemes
Certain shares held as a result of participation in some employee
share plans carry voting rights. Voting rights in respect of such shares
are exercisable via a nominee. Dividend waivers are in place in respect
of unallocated shares held in employee share plan trusts.

Change of control provisions
On 5 October 2015, the United States lodged with the district court in
MDL 2179 a proposed Consent Decree between the United States,
the Gulf states, BP Exploration & Production Inc., BP Corporation
North America Inc. and BP p.l.c., to fully and finally resolve any and all
natural resource damages claims of the United States, the Gulf states
and their respective natural resource trustees and all Clean Water Act
penalty claims, and certain other claims of the United States and the
Gulf states. Concurrently, BP entered into a definitive Settlement
Agreement with the five Gulf states (Settlement Agreement) with
respect to state claims for economic, property and other losses. On

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. The policy has been updated such that all non-audit tax
services provided by the audit firm from 2017 onwards are prohibited.
In 2016 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;
provision of the independent third party audit in accordance with US
Generally Accepted Government Auditing Standards, over the
company’s Conflict Minerals Report – where such a report is required
under the SEC rule ‘Conflict Minerals’, issued in accordance with
Section 1502 of the Dodd Frank Act; 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. In response
to the revised regulatory guidelines of the FRC, the audit committee
reviewed and updated its policies with effect from 1 January 2017. The
defined maximum level for pre-approval will be reduced in 2017 in line
with Financial Reporting Council guidance on ‘non-trivial’ engagements.
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 35 and Audit committee report on page 69 for
details of fees for services provided by auditors.)

Directors’ report information
This section of BP Annual Report and Form 20-F 2016 forms part of,
and includes certain disclosures which are required by law to be
included in, the Directors’ report.

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4 April 2016, the district court approved the Consent Decree, at which
time the Consent Decree and Settlement Agreement became
effective. The federal government and the Gulf states may jointly elect
to accelerate the payments under the Consent Decree in the event of
a change of control or insolvency of BP p.l.c., and the Gulf states
individually have similar acceleration rights under the Settlement
Agreement. For further details of the Consent Decree and the
Settlement Agreement, see Legal proceedings on page 261.

Greenhouse gas emissions
The disclosures in relation to greenhouse gas emissions are included
in Sustainability – Climate change on page 43.
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) – (11)
(12), (13) Dividend waivers
(14)

Page
145
Not applicable
268
Not applicable

Cautionary statement
In order to utilize the ‘safe harbor’ provisions of the United States Private
Securities Litigation Reform Act of 1995 (the ‘PSLRA’), BP is providing
the following cautionary statement. This document contains certain
forecasts, projections and forward-looking statements – that is,
statements related to future, not past events – with respect to the
financial condition, results of operations and businesses of BP and
certain of the plans and objectives of BP with respect to these items.
These statements may generally, but not always, be identified by the
use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’,
‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘anticipates’, ‘plans’,
‘we see’ or similar expressions. In particular, among other statements,
(i) certain statements in the Chairman’s letter (pages 4-5), the Group
chief executive’s letter (pages 6-7), the Strategic report (inside cover and
pages 2-50), Additional disclosures (pages 239-270) and Shareholder
information (pages 271-279), including but not limited to statements
under the headings ‘The changing world of energy’, ‘How we run our
business’, ‘Our strategy’ and ‘Challenging global energy markets’ and
including but not limited to statements regarding plans and prospects
relating to future value creation, near and long-term growth, capital
discipline and growth in sustainable free cash flow and shareholder
distributions; future dividend and optional scrip dividend payments;
expectations regarding world energy demand through 2035, including
the growth in relative demand for renewables, oil and gas; expectations
regarding the use of electric vehicles and the expansion of BP’s global
business services organization; expectations regarding future emissions
and carbon policies and the share of BP’s direct emissions subject to
such policies; plans and expectations regarding future capital
expenditure, reduction in BP’s cash costs, Other businesses and
corporate annual charges (excluding non-operating items), proceeds
from divestments, non-operating restructuring charges, net debt levels,
and the timing and amount of future payments relating to the Gulf of
Mexico oil spill; statements that PSC settlement claims are expected to
be substantially paid in 2017; plans and expectations regarding sales
commitments of BP and its equity-accounted entities; expectations
regarding underlying production and capital investment in 2017;
expectations regarding oil prices and their impact on BP’s return on
average capital employed; expectations regarding organic capital
expenditure and the cash balance point in 2017; plans regarding gearing;
plans and expectations for operating cash flow excluding payments
relating to the Gulf of Mexico oil spill to cover organic capital expenditure
and the dividend at an oil price of around $60 per barrel by the end of
2017 and plans and expectations for driving the balance point closer to
$55 per barrel by the end of 2017; expectations that the cash balance
point will reduce over the next five years; expectations regarding the
effective tax rate in 2017; plans and expectations regarding future levels
of BP production through 2020, including increases in production from
new projects; plans and expectations regarding investment,
development, and production levels and the timing thereof with respect

to projects and partnerships in Abu Dhabi, Alaska, Argentina, Australia,
Azerbaijan, Bolivia, Brazil, Canada, China, Egypt, Georgia, India,
Indonesia, Kuwait, Mauritania, Mexico, Oman, Russia, Senegal, Trinidad
& Tobago, Turkey, the UK North Sea, and the United States; plans and
expectations regarding plant reliability; plans and expectations regarding
the share of LNG production from the Tangguh gas facility sold to the
Indonesian state electricity company, the number of jobs the facility will
create and the share of the Papuan workforce at the facility;
expectations regarding refining margins and refining turnarounds; plans
to undertake joint exploration and research with Rosneft; plans and
expectations with regard to the strategic aims of Air BP and the
lubricants business; plans to retain our carbon neutral accreditation at
certain Air BP-operated facilities and to reduce emissions by 5% over
the next 10 years; plans and expectations regarding the upgrades at
plants in Belgium and South Carolina and the resulting increase in
manufacturing efficiency at those facilities; plans and expectations
regarding additions to BP’s fleet of oil tankers and LNG tankers;
expectations regarding the actions of contractors and partners and their
terms of service; BP’s aim to maintain a diverse workforce, create an
inclusive environment and ensure equal opportunity, including for
women to represent 25% of group leaders by 2020; policies and goals
related to risk management plans to address employee engagement;
plans and expectations to reduce BP’s reliance on US persons at the
Rhum gas field; plans regarding activities, dealings and transactions
relating to Iran; plans and expectations regarding the sale of stakes in
Magnus and certain associated pipelines and the Sullom Voe Terminal;
plans and projections regarding oil and gas reserves, including the
turnover time of proved undeveloped reserves to proved developed
reserves; plans and expectations regarding the renewal of leases;
expectations regarding the future value of assets; expectations
regarding future regulations and policy, their impact on BP’s business
and plans regarding compliance with such regulations; plans and
expectations regarding settlement of claims related to the Deepwater
Horizon incident and related legal proceedings; 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 timing of such proceedings and BP’s
intentions in respect thereof; and (ii) certain statements in Corporate
governance (pages 51-79) and the Directors’ remuneration report (pages
80-110) 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 the appointment of Deloitte
as auditor from 2018; plans regarding the implementation of a new
remuneration policy; plans and expectations with regard to the
remuneration, pensions and other benefits of executive directors; and
goals and areas of focus of board committees, 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; delays in the processes for resolving claims; 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-

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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; cyberattacks or
sabotage; and other factors discussed elsewhere in this report
including under Risk factors (pages 49-50). 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.

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Shareholder
information

272 Share prices and listings

272 Dividends

273 Shareholder taxation information

275 Major shareholders

276 Annual general meeting

276 Memorandum and Articles of Association

278 Purchases of equity securities by the issuer and

affiliated purchasers

278

Fees and charges payable by ADSs holders

279

Fees and payments made by the Depositary to the
issuer

279 Documents on display

279 Shareholding administration

279 Exhibits

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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 market prices 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
2012
2013
2014
2015
2016

Year ended 31 December
2015: First quarter (January-March)

Second quarter (April-June)
Third quarter (July-September)
Fourth quarter (October-December)

2016: First quarter (January-March)

Second quarter (April-June)
Third quarter (July-September)
Fourth quarter (October-December)

2017: First quarter (to 16 March)

Month of
September 2016
October 2016
November 2016
December 2016
January 2017
February 2017
March 2017 (to 16 March)
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

512.00
494.20
526.80
487.50
513.24

463.10
487.50
445.05
411.50
381.80
438.15
464.40
513.24
521.20

453.25
498.45
483.70
513.24
521.20
482.95
474.55

388.56
426.50
364.40
319.90
309.10

376.70
420.15
319.90
328.80
309.10
335.07
408.63
432.15
440.80

411.60
459.30
432.15
458.95
472.80
440.80
448.00

48.34
48.65
53.48
43.85
37.68

42.10
43.85
41.52
37.53
32.38
35.59
37.28
37.68
38.68

35.39
36.83
35.27
37.68
38.68
36.20
34.55

36.25
39.99
34.88
29.35
27.01

34.93
39.27
29.35
29.90
27.01
28.67
32.50
32.53
33.10

33.06
35.55
32.53
35.29
35.73
33.33
33.10

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 16 March 2017 923,167,362 ADSs (equivalent to approximately
5,539,010,217 ordinary shares or some 28.32% of the total issued
share capital, excluding shares held in treasury) were outstanding and
were held by approximately 88,594 ADS holders. Of these, about
87,560 had registered addresses in the US at that date. One of the
registered holders of ADSs represents some 1,031,491 underlying
holders.

On 16 March 2017 there were approximately 248,855 ordinary
shareholders. Of these shareholders, around 1,570 had registered
addresses in the US and held a total of some 4,001,956 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 9.

A Scrip Dividend Programme (Scrip Programme) was approved by
shareholders in 2010 and was renewed for a further three years at the
2015 AGM. It enables BP ordinary shareholders and ADS holders to elect
to receive dividends by way of new fully paid BP ordinary shares (or ADSs

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in the case of ADS holders) instead of cash. 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 49 and other
matters that may affect the business of the group set out in Our
strategy on page 14 and in Liquidity and capital resources on
page 242.

The following table shows dividends announced and paid by the
company per ADS for the past five years.

Dividends per ADSa
2012

2013

2014

2015

2016

UK pence
US cents

UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents

March
30.57 30.90
48

June September December
30.10
48

Total
33.53 125.10
198

36.01 35.01
54
34.24 34.84
58.5
40.00 39.18
60
42.08 41.50
60

34.58
54
35.76
58.5
39.29
60
45.35
60

34.80 140.40
219
38.26 143.10
234
39.81 158.28
240
47.59 176.52
240

a Dividends announced and paid by the company on ordinary and preference shares are

provided in Financial statements – Note 9.

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.

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, inter alia 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 (1) a citizen or resident of the US,
(2) a US domestic corporation, (3) an estate whose income is subject
to US federal income taxation regardless of its source, or (4) 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 under the terms of the
deposit agreement relating to BP ADSs 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 until 5 April 2016, is
entitled to a tax credit on cash dividends paid on ordinary shares or
ADSs of the company equal to one-ninth of the cash dividend.

From 6 April 2016 the Dividend Tax Credit was replaced by a new
tax-free Dividend Allowance and dividends paid by the Company on or
after 6 April 2016 do not carry a UK tax credit. A Dividend Allowance
has been introduced whereby there is no UK tax due on the first
£5,000 of dividends received. Dividends above this level are subject to
tax at 7.5% for basic tax payers, 32.5% for higher rate tax payers and
38.1% for additional rate tax payers.

Although the first £5,000 of dividend income is not subject to UK
income tax, it does not reduce the total income for tax purposes.
Dividends within the Dividend Allowance still count towards basic or
higher rate bands, and may therefore affect the rate of tax paid on
dividends received in excess of the £5,000 allowance. For instance, if
an individual has £2,000 of the basic rate band remaining after earning
non-dividend income, and receives £6,000 of dividend income, they
will be subject to the following scenario. The Dividend Allowance will
cover the first £2,000 of dividends which fall into the remaining basic
rate band, leaving the remaining £3,000 of the allowance to use in the
higher rate band. The first £5,000 dividend income is therefore
covered by the allowance and is not subject to tax. The remaining
£1,000 of dividend income falls into the higher rate band and is taxed
at the rate of 32.5%.

How the shareholder pays the tax arising on the dividend income
depends on the amount of dividend income they receive in the tax
year. If less than £5,000 they will not need to report anything or pay
any tax. If between £5,000 and £10,000, the shareholder can pay what
they owe by: contacting the helpline; asking HMRC to change their tax
code – the tax will be taken from their wages or pension or through
completion of the ‘Dividends’ section of their tax return, where one is
being filed. If over £10,000 they will be required to file a self-
assessment tax return and should complete the ‘Dividends’ section
with details of the amounts received.

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.

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

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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. US ADS holders should consult their own
tax adviser regarding the US tax treatment of the dividend fee in
respect of dividends. 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.

As noted above in UK taxation, a US holder will not be subject to UK
withholding tax. Accordingly, the receipt of a dividend will not entitle
the US holder to a foreign tax credit.

The amount of the dividend distribution on the ordinary shares that is
paid in pounds sterling will be the US dollar value of the pounds
sterling payments made, determined at the spot pounds sterling/US
dollar rate on the date the dividend distribution is includible in income,
regardless of whether the payment is, in fact, converted into US
dollars. Generally, any gain or loss resulting from currency exchange
fluctuations during the period from the date the pounds sterling
dividend payment is includible in income to the date the payment is
converted into US dollars will be treated as ordinary income or loss
and will not be eligible for the preferential tax rate on qualified
dividend income. The gain or loss generally will be income or loss
from sources within the US for foreign tax credit limitation purposes.

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
(1) resident for tax purposes in the United Kingdom at the date of
disposal, (2) if he or she has left the UK for a period not exceeding five
complete tax years between the year of departure from and the year
of return to the UK and acquired the shares before leaving the UK and
was resident in the UK in the previous four out of seven tax years
before the year of departure, (3) a US domestic corporation resident in
the UK by reason of its business being managed or controlled in the
UK or (4) 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.

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.

Additional tax considerations
Scrip 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.

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.

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

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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 advisers
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 Guidance 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

Number of ordinary
shareholders
54,634
86,631
97,136
10,729
731
647

Percentage of total
ordinary shareholders
21.81
34.58
38.78
4.28
0.29
0.26

Percentage of total
ordinary share capital
excluding shares
held in treasury
0.01
0.24
1.55
1.12
1.44
95.64

Totals

250,508

100.00

a Includes JPMorgan Chase Bank, N.A. holding 28.31% 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
52,478
23,687
12,532
618
8
1

89,324

Percentage of total
ADS holders
58.76
26.52
14.03
0.69
0.00
0.00

Percentage of total
ADSs
0.31
1.23
3.55
1.11
0.15
93.65

100.00

a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 1,006,596 underlying shareholders.

As at 31 December 2016 there were also 1,376 preference
shareholders. Preference shareholders represented 0.43% and
ordinary shareholders represented 99.57% 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 2016 BlackRock, Inc. held 6.39% and The Capital Group
Companies, Inc held 3.22% of the voting rights of the issued share
capital of the company. As at 16 March 2017 BlackRock, Inc. held
6.14% and The Capital Group Companies, Inc held 2.91% 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 16 March 2017:

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

5,539,010,217

1,201,121,362

28.32

6.14

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 16 March 2017:

Holder

The National Farmers Union Mutual

Insurance Society

M&G Investment Management Ltd.

Hargreaves Lansdown Asset

Management Ltd.

Holder

The National Farmers Union Mutual

Insurance Society

M&G Investment Management Ltd.

Barclays Wealth

Bank J. Safra Sarasin

Holding of 8%
cumulative first
preference shares

Percentage
of class

945,000

528,150

13.07

7.30

489,641

6.77

Holding of 9%
cumulative second
preference shares

Percentage
of class

987,000

644,450

317,546

294,000

18.03

11.77

5.80

5.37

In accordance with DTR 5, Smith and Williamson Holdings Limited
notified the company that it disposed of its interest in 32,500 8%
cumulative first preference shares and BlackRock, Inc. notified the
company that its indirect interest in ordinary shares decreased below
5%, during 2014 respectively.

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.

UBS Investment Bank notified the company that its indirect interest in
ordinary shares increased above 3% on 7 May 2015 and that it
decreased below the notifiable threshold on 11 May 2015.

The Capital Group of Companies, Inc. notified the company that its
indirect interest in ordinary shares decreased below the notifiable
threshold on 21 July 2015.

UBS Investment Bank notified the company that its indirect interest in
ordinary shares increased above 3% on 4 November 2015 and that it
decreased below the notifiable threshold on 9 November 2015.

BlackRock, Inc. notified the company that its indirect interest in
ordinary shares remained above the previously disclosed threshold of
5%, on 26 November 2015, that it decreased below 5% on 4 February
2016 and that it increased above 5% on 15 February 2016.

During 2016 and 2017, BlackRock, Inc. notified the company that its
indirect interest in ordinary shares moved as follows: decreased below
the previously disclosed threshold of 5% on 28 April 2016; increased
above 5% on 9 May 2016; decreased below 5% on 29 July 2016;
increased above 5% on 8 August 2016; decreased below 5% on
4 November 2016; increased above 5% on 14 November 2016;
decreased below 5% on 9 February 2017; and increased above 5% on
22 February 2017.

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As at 16 March 2017, the total preference shares in issue comprised
only 0.43% of the company’s total issued nominal share capital
(excluding shares held in treasury), the rest being ordinary shares.

Annual general meeting
The 2017 AGM will be held on Wednesday 17 May 2017 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 2017.

BP intends to propose to shareholders at its 2018 AGM, that Deloitte
LLP be appointed as the company’s auditor for the financial year 2018.

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 279.

The company’s Articles of Association may be amended by a special
resolution at a general meeting of the shareholders. At the annual
general meeting (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. At the AGM held on 16 April 2015 shareholders
voted to adopt new Articles of Association to reflect developments in
practice and to provide clarification and additional flexibility.
Objects and purposes
BP is a public company limited by shares, 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, notice of which is first given after their
appointment 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. In addition, the company may by
special resolution remove a director before the expiration of his/her
period of office and, subject to the Articles of Association, may by
ordinary resolution appoint another person to be a director instead.
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.

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• 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.

• Any proposal concerning the giving to the director of any other

indemnity which is on substantially the same terms as indemnities
given or to be given to all of the other directors or to the funding by
the company of his expenditure on defending proceedings or the
doing by the company of anything to enable the director to avoid
incurring such expenditure where all other directors have been
given or are to be given substantially the same arrangements.
• Any proposal concerning an arrangement for the benefit of the

employees and directors or former employees and former directors
of the company or any of its subsidiary undertakings, including but
without being limited to a retirement benefits scheme and an
employees’ share scheme, which does not accord to any director
any privilege or advantage not generally accorded to the employees
or former employees to whom the arrangement relates.

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 two times 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 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. If the company exercises its right to forfeit shares and
sells shares belonging to an untraced shareholder then any dividends
or other monies unclaimed in respect of those shares will be forfeited
after a period of two years.

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 was renewed at the company’s
AGM held on 16 April 2015 for a further three years. 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.

For the purposes of determining which persons are entitled to attend
or vote at a shareholders’ meeting and how many votes such persons
may cast, the company may specify in the notice of the meeting a
time, not more than 48 hours before the time of the meeting, by
which a person who holds shares in registered form must be entered
on the company’s register of members in order to have the right to
attend or vote at the meeting or to appoint a proxy to do so.

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, provided that a duly completed
proxy form is received not less than 48 hours (or such shorter time as
the directors may determine) before the time of the meeting or
adjourned meeting or, where the poll is to be taken after the date of
the meeting, not less than 24 hours (or such shorter time as the
directors may determine) before the time of the poll.

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.

Corporations who are members of the company may appoint one or
more persons to act as their representative or representatives at any
shareholders’ meeting provided that the company may require a
corporate representative to produce a certified copy of the resolution
appointing them before they are permitted to exercise their powers.

Matters are transacted at shareholders’ meetings by the proposing
and passing of resolutions, of which there are two types: ordinary or
special.

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 clear days’ notice. The notice
period for any other general meeting is 14 clear days subject to the
company obtaining annual shareholder approval, failing which, a 21
clear 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 above under the heading Voting rights.

Under the Act, the AGM of shareholders must be held once every
year, within each six month period beginning with the day following
the company’s accounting reference date. All general meetings shall
be held at a time and place (in England) determined by the directors. If
any shareholders’ meeting is adjourned for lack of quorum, notice of
the time and place of the adjourned 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

BP Annual Report and Form 20-F 2016

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transfer and receipt of dividends and other payments in respect of
those shares and any new shares in the company issued 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 2016 are set out in Financial statements – Note 30. At
the AGM on 14 April 2016, authorization was given to the directors
to allot shares up to an aggregate nominal amount equal to
$3,081 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 $462 million, without having to
offer such shares to existing shareholders. These authorities were
given for the period until the next AGM in 2017 or 14 July 2017,
whichever is the earlier. These authorities are renewed annually at
the AGM.

Purchases of equity securities by
the issuer and affiliated
purchasers
At the AGM on 14 April 2016, authorization was given to the company
to repurchase up to 1.8 billion ordinary shares for the period until the

next AGM in 2017 or 14 July 2017, being the latest dates by which an
AGM must be held for that year. This authorization is renewed
annually at the AGM. No ordinary shares were repurchased by the
company during 2016. The following table provides 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.

2016
January 10 – January 11
May 3
September 7
November 7 – November 16
December 19
2017
January 3 – January 31
February 7
March 1 – March 16

Number of shares
purchased
by ESOPs or for
certain employee
share-based plansa

Average price
paid per share
$

1,190,000
1,650,000
1,480,908
30,412
5,280,000

Nil
250,000
Nil

5.08
5.65
5.82
5.63
6.09

5.80

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.

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

Dividend fees

Global Invest Direct (“GID”) Plan

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).

ADS holders who receive a cash dividend are charged
a fee which BP uses to offset the costs associated
with administering the ADS programme.
New investors and existing ADS holders can buy or
sell BP ADSs by enrolling in BP’s GID Plan, sponsored
and administered by the Depositary.

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.

$0.005 per BP ADS per quarter per
cash distribution.

Cost per transaction is $2.00 for
recurring, $2.00 for one-time
automatic investments, and $5.00 for
investment made by check, plus
$0.12 commission per share.

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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 2016. The Depositary reimbursed to the
company, or paid amounts on the company’s behalf to third parties, or
waived its fees and expenses, of $15,621,791.96 for the year ended
31 December 2016.

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 2016.

Category of expense reimbursed,
waived or paid directly to third parties
Fees for delivery and surrender of BP

ADSs

Dividend feesa
Total

Amount reimbursed, waived or paid
directly to third parties for the year
ended 31 December 2016
$

874,061.17
14,747,730.79
15,621,791.96

a Dividend fees are charged to ADS holders who receive a cash distribution, which BP uses to

offset the costs associated with administering the ADS programme.

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 certain 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 2016 is 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@issuerdirect.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 in this report (see Corporate governance
practices (Form 20-F Item 16G) on page 266) significant ways (if any)
in which its corporate governance practices differ from those
mandated for US companies under NYSE listing standards.

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
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
The BP ADS Depositary, 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 4.7
Exhibit 4.10
Exhibit 7

Exhibit 8

Exhibit 11
Exhibit 12
Exhibit 13
Exhibit 15.1
Exhibit 15.2
Exhibit 15.3

Exhibit 15.4
Exhibit 15.5

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 Dr B Gilvary***†
The BP Share Award Plan 2015*******†
Computation of Ratio of Earnings to Fixed Charges
(Unaudited)†
Subsidiaries (included as Note 36 to the Financial
Statements)
Code of Ethics*†
Rule 13a – 14(a) Certifications†
Rule 13a – 14(b) Certifications#†
Consent of DeGolyer and MacNaughton†
Report of DeGolyer and MacNaughton†
Administrative Agreement dated as of 13 March
2014 among the US Environmental Protection
Agency, BP p.l.c., and other BP
subsidiaries******†
Consent Decree*******†
Gulf states Settlement Agreement*******†

* 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 2010.

*** 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 2012.

***** Incorporated by reference to the company’s Annual Report on Form 20-F for the year

ended 31 December 2013.

****** Incorporated by reference to the company’s Annual Report on Form 20-F for the year

ended 31 December 2014.

******* Incorporated by reference to the company’s Annual Report on Form 20-F for the year

ended 31 December 2015.

# 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.

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Glossary
Abbreviations

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.

GHG
Greenhouse gas.

GWh
Gigawatt hour.

HSSE
Health, safety, security and environment.

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.

MW
Megawatt.

MteCO2
Million tonnes of CO2 equivalent.

NGLs
Natural gas liquids.

PSA
Production-sharing agreement.

280

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PTA
Purified terephthalic acid.

RC
Replacement cost.

SEC
The United States Securities and Exchange Commission.

Definitions
Unless the context indicates otherwise, the definitions for the
following glossary terms are given below.

Adjusted effective tax rate (ETR)
Non-GAAP measure. The adjusted ETR is calculated by dividing
taxation on an underlying replacement cost (RC) basis excluding the
impact of reductions in the rate of the UK North Sea supplementary
charge (in 2016 and 2015) by underlying RC profit or loss before tax.
Taxation on an underlying RC basis is taxation on a RC basis for the
period adjusted for taxation on non-operating items and fair value
accounting effects. Information on underlying RC profit or loss is
provided below. BP believes it is helpful to disclose the adjusted ETR
because this measure 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, period on period. The
nearest equivalent measure on an IFRS basis is the ETR on profit or
loss for the period, and a reconciliation to GAAP information is
provided on page 285.

Associate
An entity 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.

Brent
A trading classification for North Sea crude oil that serves as a major
benchmark price for purchases of oil worldwide.

Capital expenditure on an accruals basis
Non-GAAP measure. It comprises additions to property, plant and
equipment, intangible assets and investments in joint ventures and
associates, and reflects consideration payable in business
combinations. It does not include additions arising from asset
exchanges and certain other non-cash items. The nearest equivalent
measure on an IFRS basis for the group is Additions to non-current
assets. BP believes that Capital expenditure on an accruals basis
provides useful information for investors as it is the measure used by
management to plan and prioritize the group’s investment of its
resources and allows investors to understand how the group balances
funds between shareholder distributions and investment for the
future. Further information and a reconciliation to GAAP information is
provided on page 285.

Cash costs
Non-GAAP measure. Cash costs are a subset of production and
manufacturing expenses plus distribution and administration expenses
and excludes costs that are classified as non-operating items. They
represent the substantial majority of the remaining expenses in these
line items but exclude certain costs that are variable, primarily with
volumes (such as freight costs). Management believes that the
presentation of cash costs is a performance measure that provides
investors with useful information regarding the company’s financial
condition because it considers these expenses to be the principal
operating and overhead expenses that are most directly under their
control although they also include certain foreign exchange and
commodity price effects. A reconciliation to GAAP information is
provided on page 285.

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
24 and in Downstream on page 30. 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 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 margin, are generally 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 announced in respect of the year
as a percentage of the year-end share price on the respective
exchange.

Effective tax rate (ETR) on replacement cost (RC) profit or loss
Non-GAAP measure. The ETR on RC profit or loss is calculated by
dividing taxation on a RC basis by RC profit or loss before tax.
Information on RC profit or loss is provided below. BP believes it is
helpful to disclose the ETR on RC profit or loss because this measure
excludes the impact of price changes on the replacement of
inventories and allows for more meaningful comparisons between
reporting periods. The nearest equivalent measure on an IFRS basis is
the ETR on profit or loss for the period, and a reconciliation to GAAP
information is provided on page 285.

Fair value accounting effects
Non-GAAP adjustments to IFRS profit or loss. 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 physical 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. In addition,
derivative instruments are used to manage the price risk associated
with certain future natural gas sales. 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 certain
LNG and oil and gas contracts and gas sales contracts, are deferred to
match with the underlying exposure and the commodity contracts for
business requirements are accounted for on an accruals basis. We

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believe that disclosing management’s estimate of this difference
provides useful information for investors because it enables investors
to see the economic effect of these activities as a whole.

Free cash flow
Operating cash flow less net cash used in investing activities, as
presented in the group cash flow statement.

Gearing
See Net debt and net debt ratio definition.

Henry Hub
A distribution hub on the natural gas pipeline system in Erath,
Louisiana, that lends its name to the pricing point for natural gas
futures contracts traded on the New York Mercantile Exchange and
the over-the-counter swaps traded on Intercontinental Exchange.

Hydrocarbons
Liquids and natural gas. Natural gas is converted to oil equivalent at
5.8 billion cubic feet = 1 million barrels.

Inorganic capital expenditure
A subset of Capital expenditure on an accruals basis and is a
non-GAAP measure. Inorganic capital expenditure comprises
consideration in business combinations and certain other significant
investments made by the group. It is reported on an accruals basis. BP
believes that this measure provides useful information as it allows
investors to understand how BP’s management invests funds in
projects which expand the group’s activities through acquisition. A
reconciliation of capital expenditure on an accruals basis to GAAP
information is provided on page 285. See also page 240.

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 the
Upstream segment, it also includes bitumen.

LNG train
An LNG train is a processing facility used to liquefy and purify natural
gas in the formation of LNG.

Net cash margin per barrel
Net cash margin is defined by Solomon Associates as the net margin
achieved after subtracting cash operating expenses and adding any
refinery revenue from other sources. Net cash margin is expressed in
US dollars per barrel of net refinery input.

Net debt and net debt ratio (gearing)
Non-GAAP measures. 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 currency
exchange and interest rate risks relating to finance debt, for which
hedge accounting is applied, less cash and cash equivalents. The net
debt ratio is defined as the ratio of net debt to the total of net debt
plus total shareholders’ equity. All components of equity are included
in the denominator of the calculation. 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’. See Financial statements – Note 26
for information on gross debt, which is the nearest equivalent
measure to net debt on an IFRS basis.

We are unable to present reconciliations of forward-looking information
for net debt ratio to gross debt ratio, because without unreasonable
efforts, we are unable to forecast accurately certain adjusting items
required to present a meaningful comparable GAAP forward-looking
financial measure. These items include fair value asset (liability) of
hedges related to finance debt and cash and cash equivalents, that are
difficult to predict in advance in order to include in a GAAP estimate.

Net income per barrel
Non-GAAP measure. Net income per barrel is calculated by taking
underlying replacement cost profit before interest and tax for the
Downstream segment, deducting tax at an assumed 28% effective
tax rate and dividing the result by the group’s total refining capacity.
BP uses this measure to assess performance relative to peer
companies.

Net generating 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-joint venture basis, which includes 100% of the capacity of
equity-accounted entities where BP has partial ownership.

Non-operating items
Charges and credits are included in the financial statements 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.
Non-operating items within equity-accounted earnings are reported
net of incremental income tax reported by the equity-accounted entity.
An analysis of non-operating items by segment and type is shown on
page 240.

Operating cash flow
Net cash provided by (used in) operating activities as stated in the
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 cash flow excluding amounts related to the Gulf of
Mexico oil spill
Non-GAAP measure. It is calculated by excluding post-tax operating
cash flows relating to the Gulf of Mexico oil spill as reported in
Financial statements – Note 2 from net cash provided by operating
activities as reported in the group cash flow statement. BP believes it
is helpful to disclose net cash provided by operating activities
excluding amounts related to the Gulf of Mexico oil spill because this
measure allows for more meaningful comparisons between reporting
periods. The nearest equivalent measure on an IFRS basis is net cash
provided by operating activities.

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.

Operating cash margin
Operating cash margin is operating cash flow divided by the applicable
number of barrels of oil equivalent produced.

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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
A subset of Capital expenditure on an accruals basis and is a
non-GAAP measure. Organic capital expenditure comprises capital
expenditure on an accruals basis less inorganic capital expenditure. BP
believes that this measure provides useful information as it allows
investors to understand how BP’s management invests funds in
developing and maintaining the group’s assets. An analysis of
additions to non-current assets by segment, and a reconciliation of
capital expenditure on an accruals basis to GAAP information is
provided on page 285. See also page 240.

We are unable to present reconciliations of forward-looking information
for organic capital expenditure to additions to non-current assets,
because without unreasonable efforts, we are unable to forecast
accurately certain adjusting items required to present a meaningful
comparable GAAP forward-looking financial measure. These items
include changes in decommissioning assets and asset exchanges, that
are difficult to predict in advance in order to include in a GAAP estimate.

Plant reliability
Plant reliability is calculated taking 100% less the ratio of total
unplanned plant deferrals divided by installed production capacity.
Unplanned plant deferrals are associated with the topside plant and
where applicable the subsea equipment (excluding wells and
reservoir). Unplanned plant deferrals include breakdowns 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.

Realizations
Realizations are the result of dividing revenue generated from
hydrocarbon sales, excluding revenue generated from purchases
made for resale and royalty volumes, by revenue generating
hydrocarbon production volumes. Revenue generating hydrocarbon
production reflects the BP share of production as adjusted for any
production which does not generate revenue. Adjustments may
include losses due to shrinkage, amounts consumed during
processing, and contractual or regulatory host committed volumes
such as royalties. For the Upstream segment, realizations include
transfers between businesses.

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.

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 IFRS.
RC profit or loss for the group is a non-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. The nearest equivalent measure on
an IFRS basis is profit or loss attributable to BP shareholders. See
Financial statements – Note 5, and a reconciliation to GAAP
information is provided on page 240.
RC profit or loss per share
Non-GAAP measure. Earnings per share is defined in Financial
statements – Note 10. RC profit or loss per share is calculated using
the same denominator. The numerator used is RC profit or loss
attributable to BP shareholders rather than profit or loss attributable to
BP shareholders. BP believes it is helpful to disclose the RC profit or
loss per share because this measure excludes the impact of price
changes on the replacement of inventories and allows for more
meaningful comparisons between reporting periods. The nearest
equivalent measure on an IFRS basis is basic earnings per share
based on profit or loss for the period attributable to BP shareholders,
and a reconciliation to GAAP information is provided on page 285.
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.
Return on average capital employed
Non-GAAP measure. Return on average capital employed (ROACE) is
underlying replacement cost profit, after adding back non-controlling
interest and interest expense net of notional tax at an assumed 35%,
divided by average capital employed, excluding cash and cash
equivalents and goodwill. BP believes it is helpful to disclose the
ROACE because this measure gives an indication of the company’s
capital efficiency. The nearest GAAP measures of the numerator and
denominator are profit or loss for the period attributable to BP
shareholders and average capital employed respectively. The
reconciliation of the numerator and denominator is provided on
page 285.
We are unable to present forward-looking information of the nearest
GAAP measures of the numerator and denominator for ROACE,
because without unreasonable efforts, we are unable to forecast
accurately certain adjusting items required to calculate a meaningful
comparable GAAP forward-looking financial measure. These items
include inventory holding gains or losses and interest net of tax, that
are difficult to predict in advance in order to include in a GAAP
estimate.
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 oil and gas
Natural oil and gas reservoirs locked in hard sandstone rocks with low
permeability, making the underground formation extremely tight.
UK National Balancing Point
A virtual trading location for sale, purchase and exchange of UK natural
gas. It is the pricing and delivery point for the Intercontinental
Exchange natural gas futures contract.
Unconventionals
Resources found in geographic accumulations over a large area, that
usually present additional challenges to development such as low
permeability or high viscosity. Examples include shale gas and oil,
coalbed methane, gas hydrates and natural bitumen deposits. These
typically require specialized extraction technology such as hydraulic
fracturing or steam injection.
Underlying production
Production after adjusting for divestments and entitlement impacts in
our production-sharing agreements. 2017 underlying production does
not include the Abu Dhabi onshore concession renewal.

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Underlying RC profit or loss
Non-GAAP measure. RC profit or loss after adjusting for non-operating
items and fair value accounting effects. See pages 240 and 285 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. A
reconciliation to GAAP information is provided on page 240.

Underlying RC profit or loss per share
Non-GAAP measure. Earnings per share is defined Financial
statements – Note 10. Underlying RC profit or loss per share is
calculated using the same denominator. The numerator used is
underlying RC profit or loss attributable to BP shareholders rather than
profit or loss attributable to BP shareholders. BP believes it is helpful
to disclose the underlying RC profit or loss per share because this
measure 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, period on period. The nearest
equivalent measure on an IFRS basis is basic earnings per share
based on profit or loss for the period attributable to BP shareholders
and a reconciliation to GAAP information is provided on page 285.

Trade marks

Trade marks of the BP group appear throughout this report.
They include:

ACTIVE
Aral
ARCO
BP
Castrol
DUALOCK
EDGE
GTX
MAGNATEC
PTAir

Albert Heijn to go is a registered trade mark of
Albert Heijn.
Fulcrum BioEnergy is a registered trade mark of
Fulcrum BioEnergy, Inc.
M&S Simply Food is a registered trade mark of
Marks & Spencer plc.
REWE to go is a registered trade mark of REWE.
RocketRoute is a registered trade mark of
RocketRoute Limited.
Pick n Pay is a registered trade mark of Pick n Pay
Stores Limited.

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Non-GAAP measures reconciliations

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 280.

Upstream
Unrecognized (gains) losses brought forward from previous perioda
Favourable (unfavourable) impact relative to management’s measure of performance
Exchange translation gains (losses) on fair value accounting effects
Unrecognized (gains) losses carried forward
Downstreamb
Unrecognized (gains) losses brought forward from previous perioda
Favourable (unfavourable) impact relative to management’s measure of performance
Unrecognized (gains) losses carried forward

Favourable (unfavourable) impact relative to management’s measure of performance – by region
Upstream
US
Non-US

Downstreamb
US
Non-US

Taxation credit (charge)

2016

263
(637)
(19)
(393)

377
(448)
(71)

(379)
(258)
(637)

(321)
(127)
(448)
(1,085)
329
(756)

2015

191
105
–
296

188
156
344

(66)
171
105

102
54
156
261
(56)
205

$ million

2014

160
31
–
191

(679)
867
188

23
8
31

914
(47)
867
898
(341)
557

a 2016 brought forward fair value accounting effect balances include a $33-million adjustment between Upstream and Downstream as part of the transfer of certain emission trading balances

between these segments.

b Fair value accounting effects arise solely in the fuels business.

Reconciliation of non-GAAP information

Upstream
RC profit (loss) before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
RC profit (loss) 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 (loss) before interest and tax adjusted for fair value accounting effects
Impact of fair value accounting effects
Profit (loss) before interest and tax

2016

2015

1,211
(637)
574

5,610
(448)
5,162

655
(1,085)
(430)

(1,042)
105
(937)

6,955
156
7,111

(8,179)
261
(7,918)

$ million

2014

8,903
31
8,934

2,871
867
3,738

5,514
898
6,412

Reconciliation of production and manufacturing expenses and distribution and administration expenses to
cash costs

Income statement data

Production and manufacturing expenses
Distribution and administration expenses

Total costs
Adjusted for certain non-operating items

Gulf of Mexico oil spill
Restructuring, integration and rationalization costs
Other items

Adjusted for certain variable costs

Transportation and shipping costs
Other variable costs

Cash costs

2016

2015

29,077
10,495
39,572

6,640
763
(59)
32,228

8,179
3,892
20,157

37,040
11,553
48,593

11,709
1,088
(121)
35,917

8,945
3,181
23,791

$ million

2014

27,375
12,266
39,641

781
441
19
38,400

8,777
2,445
27,178

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285

Reconciliation of basic earnings per ordinary share to RC profit (loss) per share and to underlying RC profit
per share

Per ordinary share – cents

Profit (loss) for the yeara
Inventory holding (gains) losses, before tax
Taxation charge (credit) on inventory holding gains and losses

RC profit (loss) for the year

Net (favourable) unfavourable impact of non-operating items and fair value

accounting effects, before tax

Taxation charge (credit) on non-operating items and fair value accounting effects

Underlying RC profit for the year

a Profit attributable to BP shareholders.

2016

0.61
(8.52)
2.58

(5.33)

35.99
(16.87)

13.79

2015

2014

2013

(35.39)
10.31
(3.10)

(28.18)

82.23
(21.83)

32.22

20.55
33.78
(10.43)

43.90

44.79
(22.69)

66.00

123.87
1.53
(0.32)

125.08

(48.83)
(5.33)

70.92

Reconciliation of additions to non-current assets to capital expenditure on an accruals basis

2012

57.89
3.12
(0.96)

60.05

32.11
(2.45)

89.71

$ million

Additions to non-current assetsb

Upstream
Downstream
Rosneft
Other businesses and corporate

Additions to other investments
Element of business combinations not related to non-current assets
(Additions to) reductions in decommissioning asset
Asset exchangesc

2016

2015

2014

2013

2012

17,879
3,109
–
216

21,204

48
(4)
656
(2,525)

17,635
2,130
–
315

20,080

35
(31)
(553)
(73)

22,587
3,121
–
784

26,492

160
(366)
(2,505)
(288)

19,499
4,449
11,941
1,027

36,916

41
39
(384)
(5)

22,603
5,246
–
1,419

29,268

33
(72)
(4,025)
(157)

Capital expenditure on an accruals basis

19,379

19,458

23,493

36,607

25,047

b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
c 2016 principally relates to the contribution of BP’s Norwegian upstream business into Aker BP ASA in exchange for a 30% interest in Aker BP ASA and the dissolution of the group’s German

refining joint operation with Rosneft.

Reconciliation of effective tax rate (ETR) to ETR on RC profit or loss and adjusted ETR
Taxation (charge) credit

Taxation on profit or loss for the year
Adjusted for taxation on inventory holding gains and losses

Taxation on a RC profit or loss basis

Adjusted for taxation on non-operating items and fair value accounting effects
Adjusted for the impact of the reduction in the rate of the UK North Sea

supplementary charge

Adjusted taxation

Effective tax rate

ETR on profit or loss for the year
Adjusted for inventory holding gains and losses

ETR on RC profit or loss

Adjusted for non-operating items and fair value accounting effects
Adjusted for the impact of the reduction in the rate of the UK North Sea

supplementary charge

Adjusted ETR

2016

2,467
(483)

2,950

3,162

434

(646)

2016

107
(31)

(69)

2015

3,171
569

2,602

4,000

915

$ million

2014

2013

2012

(947)
1,917

(2,864)

4,171

(6,463)
60

(6,523)

1,009

(6,880)
183

(7,063)

467

–

(2,313)

(7,035)

(7,532)

(7,530)

2015

2014

2013

33
1

(15)

19
7

–

21
–

–

2012

38
–

(8)

–

286

BP Annual Report and Form 20-F 2016

Return on average capital employed (ROACE)

Profit (loss) for the year attributable to BP shareholders
Inventory holding (gains) losses, net of tax
Non-operating items and fair value accounting effects, net of tax

Underlying RC profit

Interest expense, net of taxa
Non-controlling interests

Adjusted underlying RC profit

Total equity
Gross debt

Capital employed (2016 average $153,349 million)
Less: Goodwill

Cash and cash equivalents

2016

2015

115
(1,114)
3,584

2,585

635
57

(6,482)
1,320
11,067

2014

3,780
4,293
4,063

2013

23,451
230
(10,253)

5,905

12,136

13,428

576
82

546
223

549
307

$ million

2012

11,017
411
5,643

17,071

549
234

3,277

6,563

12,905

14,284

17,854

96,843
58,300

155,143
11,194
23,484

98,387
53,168

151,555
11,627
26,389

112,642
52,854

165,496
11,868
29,763

130,407
48,192

178,599
12,181
22,520

119,752
48,800

168,552
12,190
19,635

120,465

113,539

123,865

143,898

136,727

Average capital employed excluding goodwill and cash and cash equivalents

117,002

118,702

133,882

140,313

133,457

ROACE

a Calculated on a post-tax basis using a notional tax rate of 35%.

2.8%

5.5%

9.6%

10.2%

13.4%

The Directors’ report on pages 51-79, 111-112, 187-214 and 239-287 was approved by the board and signed on its behalf by David J Jackson,
company secretary on 6 April 2017.

BP p.l.c.
Registered in England and Wales No. 102498

BP Annual Report and Form 20-F 2016

287

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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
6 April 2017

288

BP Annual Report and Form 20-F 2016

Cross reference to Form 20-F

A.
B.
C.
D.

A.
B.
C.
D.
E.
F.
G.

A.
B.
C.
D.
E.

A.
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A.
B.

A.
B.
C.
D.
E.
F.

A.
B.
C.
D.
E.
F.
G.
H.
I.

A.
B.
C.
D.

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
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240-241
n/a
n/a
49-50

2-3, 21-39, 136-146, 153-155, 242-243, 257, 276, 291
2-19, 20-47, 53, 130, 142-145, 242, 244-250, 257-261, 269-270
23, 180, 291
23, 29, 38, 150, 164, 212-214, 243-256, 265
None

21-39, 49-50, 123, 125-142, 145, 153-155, 163, 165-168, 168-171, 242, 257-258, 265-266
18, 22, 124-125, 132, 150, 163-168, 211-212, 242-243
12, 22, 42, 145
8-9, 20, 21-23, 26, 31
164-165, 242-243
243
269

52-61, 65
18-19, 80-110, 178
52-57, 62-79, 80-110
46, 179
46, 80-110, 157, 179

275
153-154, 266
n/a

119-186, 242, 261-264, 272-273
146

272
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272
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n/a

n/a
275-278
265
273
273-275
n/a
n/a
279
180
165-171

n/a
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278-279
None
None
47-48, 120-121, 267
56, 69, 267
267
72, 179, 268
None
278
None
266-267
n/a
119-214
279

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289

Information about this report

Registered office and our worldwide
headquarters:

BP p.l.c.
1 St James’s Square
London SW1Y 4PD
UK
Tel +44 (0)20 7496 4000

Registered in England and Wales
No. 102498.
London Stock Exchange symbol ‘BP.’

Our agent in the US:

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US
Tel +1 281 366 2000

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 2016. A cross reference to Form 20-F requirements
is included on page 289.

This document contains the Strategic report on the inside front cover and pages 2-50 and the
Directors’ report on pages 51-79, 111-112, 187-214 and 239-287. 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 Guidance and Transparency Rules. The Directors’ remuneration
report is on pages 80-110. The consolidated financial statements of the group are on
pages 113-186 and the corresponding reports of the auditor are on pages 114-121. The parent
company financial statements of BP p.l.c. are on pages 215-238.

The Directors’ statements (comprising the Statement of directors’ responsibilities; Risk
management and internal control; Going concern; Longer-term viability; and Fair balanced and
understandable), the independent auditor’s report on the annual report and accounts to the
members of BP p.l.c., the parent company financial statements of BP p.l.c. and corresponding
auditor’s report, a non-GAAP measure of operating cash flow excluding the Gulf of Mexico oil spill
payments in the group chief executive’s letter on page 6 and in the tables on pages 18 and 22 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 2016 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 2016,
forms any part of this document. References in this document to other documents on the BP
website, such as BP Energy Outlook, BP Sustainability Report, BP Statistical Review of World
Energy and BP Technology 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 272 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.

* See Glossary.

290

BP Annual Report and Form 20-F 2016

Acknowledgements

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Printed in the UK by Pureprint Group using their

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