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A year of strong
delivery and growth
BP Annual Report and Form 20-F 2017
4
Contents
Strategic report
Overview
2
BP at a glance
4
How we run our business
6
Chairman’s letter
Group chief executive’s letter
8
10 The changing world of energy
Strategy
12 Our strategy
14 A year of delivery
18 Measuring our progress
Performance
20 Global energy markets
21 Group performance
26 Upstream
32 Downstream
38 Rosneft
41 Other businesses and corporate
41 Gulf of Mexico oil spill
42 Alternative Energy
Innovation in BP
44
47 Sustainability
47 Safety and security
50 Climate change
51 Managing our impacts
51 Value to society
52 Human rights
52 Environment
52 Ethical conduct
53 Our people
55 How we manage risk
57 Risk factors
Corporate governance
Additional disclosures
Introduction from the chairman
60 Board of directors
66 Executive team
70
72 Board activity in 2017
76 Shareholder engagement
76
77 Audit committee
84
International advisory board
Safety, ethics and environment
assurance committee
Remuneration committee
86
87
Geopolitical committee
88 Chairman’s committee
89 Nomination committee
90 Directors’ remuneration report
113 Directors’ statements
Financial statements
115 Consolidated financial statements
of the BP group
130 Notes on financial statements
191 Supplementary information on
oil and natural gas (unaudited)
219 Parent company financial
statements of BP p.l.c.
247 Contents
Including information on liquidity
and capital resources, oil and gas
disclosures, upstream regional
analysis and legal proceedings.
Shareholder information
279 Contents
Including information on dividends,
our annual general meeting
and share prices.
289 Glossary
294 Non-GAAP measures reconciliations
297 Signatures
298 Cross-reference to Form 20-F
299
Information about this report
Glossary
Words with this symbol
defined in the glossary on page 289.
are
Cautionary statement
This document should be read
in conjunction with the cautionary
statement on page 277.
The energy we produce serves
to power economic growth
and lift people out of poverty.
The way heat, light and mobility
are delivered is changing. 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.
Book 1.indb 1
03/04/2018 16:38:52
BP Annual Report and Form 20-F 2017
1
BP at a glance
We are a global energy business
with wide reach across the
world’s energy system. We have
operations in Europe, North and
South America, Australasia, Asia
and Africa.
BP in action
Highlights of some of
our activities in 2017.
Scale
74,000 70
employees
countries
18,441
million barrels of oil
equivalent – proved
hydrocarbon reservesa
18,300
retail sites
1.5bn
barrels of oil equivalent
transported by
BP shipping
a On a combined basis of subsidiaries
and equity-accounted entities.
US
Achieved record crude
throughput levels at
Whiting refinery, and listed
BP Midstream Partners as
a separate company.
Europe
Established Lightsource
BP – Europe’s biggest
developer of large-scale
solar projects, and achieved
record production at our
Geel petrochemicals plant
in Belgium.
Azerbaijan
Signed a contract that
will help maximize
recovery from the
Azeri-Chirag-Deepwater
Gunashli fields over
the next 32 years.
Trinidad
Made two significant
gas discoveries with the
Savannah and Macadamia
exploration wells.
Senegal
Made a major gas
discovery offshore
Senegal with joint
venture partner
Kosmos Energy.
Mexico
Opened more than 120 retail
sites, and became one of the
first private companies
to supply natural gas
to its domestic market.
Gulf of Mexico
Found significant additional
oil resources at our Atlantis
field using new seismic
imaging technology.
Argentina
Formed a new integrated
energy company with
Bridas, to create the
country’s largest privately
owned energy company.
Egypt
Made a gas discovery
in the North Damietta
Offshore Concession
in the East Nile Delta.
2
See Glossary
BP Annual Report and Form 20-F 2017
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03/04/2018 16:39:08
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Performance
$3.4bn 3.6
18
Data as at or for the year ended
31 December 2017 unless
otherwise stated.
profit attributable to
BP shareholders
million barrels of oil
equivalent per day –
hydrocarbon production
tier 1 process
safety events
(2016 $115 million) KPI
(2016 3.3mmboe/d) KPI
(2016 16) KPI
KPI
See key performance
indicators on page 18.
$6.2bn
143%
underlying replacement
cost profit
group proved reserves
replacement ratio a
(2016 $2.6 billion) KPI
(2016 109%) KPI
Russia
Agreed to develop
resources in the
Kharampurskoe and
Festivalnoye licence areas
jointly with Rosneft.
China
Sold our interest in
SECCO petrochemical
company to Sinopec.
a On a combined basis of subsidiaries
and equity-accounted entities.
We delivered seven major
projects in 2017
1 Taurus and Libra
2 Trinidad onshore
compression
3 Quad 204
4 Persephone
5 Juniper
6 Khazzan Phase 1
7 Zohr
See A year of delivery on
page 14.
Indonesia
Established
a retail joint
venture with
AKR.
India
Agreed to work with
Reliance Industries
in areas such as
differentiated fuels and
lower carbon energy
solutions.
More information
Group performance
Page 21
Upstream
Page 26
Downstream
Page 32
Rosneft
Page 38
Alternative Energy
Page 42
Book 1.indb 3
03/04/2018 16:39:12
BP Annual Report and Form 20-F 2017
See Glossary
3
3
How we run our business
Business model foundations
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 and
equip our people with the right skills for
the future. Our performance and ability to
thrive globally depends on it.
See Safety and security on page 47.
See Our people on page 53.
Finding oil and gas
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 such
as paints, clothes and packaging.
We have a diverse portfolio across
businesses, resource types and geographies.
Having upstream and downstream
businesses, along with well-established
trading capabilities, helps to mitigate the
impact of commodity pricing cycles. Our
geographic reach gives us access to growing
markets and new resources, as well as
diversifying exposure to geopolitical events.
We believe that our long history,
well-recognized brands and customer
offers, combined with our unique partnership
with Rosneft, help differentiate us from
our peers.
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, sustainable and
positive impacts in those communities
through our social investments.
bp.com/society
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, and 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 divest them if they do not
fit with our strategic priorities. We develop
the resources that meet our return threshold,
and produce hydrocarbons that 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 30.
We also seek to grow or extend the life of
existing fields – such as our Quad 204 major
project which aims to unlock additional
resources from the Schiehallion area
of the UK North Sea.
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, carbon products and
currencies. BP’s traders complete around
550,000 transactions and serve more
than 12,000 customers across some
140 countries in a year. Our customers
range from independent power producers
to utilities and municipalities. In addition we are
helping to meet LNG demand in Asia including
developments in China and Vietnam.
4
BP Annual Report and Form 20-F 2017
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03/04/2018 16:39:15
Technology, 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 Innovation in BP on page 44.
See Rosneft on page 38.
See How we manage risk on page 55.
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Transporting and trading
Manufacturing
Marketing fuels and products
Generating renewable energy
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.
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.
Generating renewable energy
We have been investing in renewables
for many years – and our focus today is on
biofuels, biopower, wind energy and solar
energy. We operate a biofuels business in
Brazil, using 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, and develop
and deploy technology in our wind business
to drive efficiency. Through our acquisition of
Clean Energy’s renewable natural gas
business, we are helping to power vehicle
fleets from organic waste. And in solar
energy we will target the growing demand
for large-scale solar projects worldwide,
including with our partner Lightsource.
Book 1.indb 5
03/04/2018 16:39:18
BP Annual Report and Form 20-F 2017
5
5
Chairman’s letter
Our goals aim to balance society’s need for more
energy with our clear ambition of playing our
part in the transition to a lower carbon world. We
are investing for the future in both hydrocarbons
and in technologies which will be important in
that transition.
Dear fellow shareholder,
In 2017, the global economy continued to be strong
and to grow while concerns around the geopolitical
environment increased. For BP, as a global business,
this was the backdrop to our operations.
Against this background we have had a strong year. A
year in which there was delivery and growth across all
our businesses as Bob describes later in his letter. This
was achieved with continued strong focus on safety. It’s
an impressive performance from a great team. They are
now fully into their stride and are performing very well.
All of this gave us confidence to continue the dividend
at 10 cents per ordinary share through 2017 and
shareholders can still take dividends in shares rather than
cash. In the fourth quarter we restarted share buybacks
to offset the dilutive effects of the scrip shares.
It remains the board’s policy to grow sustainable free
cash flow and distributions to shareholders.
So, a strong year and an important first year in the
delivery of the commitment we made in 2016 to
shareholders. So, I’d like to take stock and reflect on
where BP is now and the progress that we’ve made over
the past eight years.
BP’s path
We were faced with a crisis in 2010 that could have
threatened the very being of the company. A crisis that
should never have happened. It required resolute action
on many fronts to see us through and it is a great tribute
to everyone in BP that the foundations were laid for our
recovery.
This involved doing things differently and thinking
differently. We had to act simultaneously on many
fronts. We had to address the issues in the US while
restructuring our investments in Russia – and all the
while ensuring that we had a clear strategy for delivering
value for our shareholders. All of this in a world that is
looking towards a transition to lower carbon.
In addressing these challenges, BP showed a deep
resilience. With the leadership of Bob and his team the
whole organization was engaged with the board playing a
full role.
It is from this resilience that we have been able to set a
clear strategy with goals out to 2021. A strategy which
will grow BP and be responsive to the many changes that
are happening in the world around us.
Our challenge for the future
Our goals aim to balance society’s need for more energy
with our clear ambition of playing our part in the transition
to a lower carbon world. We are investing for the future in
both hydrocarbons and in technologies which will be
important in that transition. The world is changing
quickly, quicker than we have seen before. There is no
one solution and no one right way ahead. Our approach is
clearly aimed at being flexible and responsive.
Above: Meeting with investors at
the 2017 annual general meeting.
6
BP Annual Report and Form 20-F 2017
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$7.9 bn
total dividends distributed
to BP shareholders
5.7%
ordinary shareholders
annual dividend yield
5.7%
ADS shareholders
annual dividend yield
Whatever scenario we look at, whether from BP or the
IEA, there will need to be investment to ensure that
sufficient hydrocarbons are available during the transition
for the years to come. The world will continue to need
supplies of hydrocarbons. We need the understanding
and trust of society to make these investments to meet
this global demand. Renewables cannot be developed
quickly enough to meet the increasing need for energy.
This is not a choice between two investment
approaches, both are needed for the world to be able to
grow. Our strategic priorities address this. We are
committed and we demonstrate that commitment in
reports that we will soon publish.
Remuneration
Executive remuneration remains a clear issue of focus
for shareholders and society. I would like to thank our
shareholders for the support which you gave to our new
remuneration report at the 2017 AGM. This was an
important step forward in regaining your confidence.
As is clear from Dame Ann Dowling’s letter later in this
report, we are implementing this policy in a considered
way. As is the case with the way remuneration works,
there are awards maturing which are governed by our
previous policy. We have carefully considered the impact
of these. Working with the executives, the committee
has exercised appropriate discretion to reflect your
experience as shareholders over the past three years.
Ann will be standing down from this committee at the
AGM after three years in the chair. I would like to thank
her for all the work that she has done in leading the
committee through some very difficult times. Paula
Reynolds will take the chair of this committee.
The board
The board has continued to work with Bob and his team
on many issues relating to our strategy, our oversight of
the risks that BP faces and our understanding of the
evolving challenges of the lower carbon transition.
Our oversight of these risks is principally carried out
through the work of our committees. However there are
certain risks, such as cyber security, where it is important
that it is considered by the board.
As a board we know that we can only bring long-term
value to our shareholders if we understand the needs of
and serve the communities in which we work. We need
to listen to and be responsive to the voices of those
communities and of our own employees.
Membership of the board continues to evolve. Paul
Anderson will be retiring at the AGM in May. Paul joined
the board two months before the Deepwater Horizon
accident. He has very deep experience of the energy
industry and has been a major source of advice and
counsel to me and to the board over these years. Paul
has made a great contribution to the board and its
committees over some difficult times. I thank him on
my own behalf and on behalf of the board.
Melody Meyer was elected to the board at the 2017
AGM. Melody has an extensive career in global oil and
gas at Chevron. The board is proposing that Dame Alison
Carnwath be elected as a director at the 2018 AGM.
Alison has extensive financial experience both as an
executive and non-executive. She has worked with
global organizations and will bring a broad range of skills
to the BP board and to the audit committee which she
will join upon appointment. Both these appointments
emphasize the board’s commitment to diversity. This will
continue to enhance independent thinking and healthy
challenge.
Our purpose
BP has a clear purpose. Our role is to produce energy
which can power economic growth and lift people out
of poverty. We need to do this in a way that responds to
the ambition of a world for a low carbon future. We have
made considerable progress in 2017. It has been a great
year, but we must not be complacent. We are in a
competitive environment in a quickly changing world and
our business needs to be ready to meet those demands.
Bob and his team have once again done an excellent job
in steering BP through this year and setting a course for
the future. Thank you to Bob and the team, to my
colleagues on the board and to all our employees for all
their work during the year. My thanks also go to you our
shareholders for your support of BP.
I will be standing down during 2018 at some time after
the May AGM and as I look back I feel good about the
company. It’s in a great position to grow. I am sure that I
will have the opportunity to thank you for the support you
have given me in due course.
Carl-Henric Svanberg
Chairman
29 March 2018
Above: Visiting Aker’s Tranby
technology centre near Oslo.
More information
Corporate governance
Page 59
BP Annual Report and Form 20-F 2017
See Glossary
7
7
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03/04/2018 16:39:30
Group chief executive’s letter
We said that 2017 would be a very important
year for BP. We set out ambitious plans for the
year and we delivered on them.
$3.4bn
profit attributable to
BP shareholders
Dear fellow shareholder,
In this report last year, BP set out a five-year strategy and
promised a story of growth. One year into that five-year
plan I am pleased to report that your company has just
delivered a significant year of both disciplined execution
and exciting growth.
In many ways it was an extraordinary year for BP. Here
are some of the headlines:
• Underlying profit $6.2 billion.
• Upstream production up 12%.
• Record earnings in Downstream.
• Our most successful year for exploration since 2004.
• Group reserves replacement ratio the highest in
10 years.
Of course, we were helped by an improving oil price.
But that only tells part of the story. 2017 was a year
where we again maintained our improved trend in
safety performance for most of our main personal and
process safety metrics, although we have seen a slight
increase in our tier 1 events. Better safety and improved
operational reliability, combined with strong discipline in
our cash and capital costs, fed through into our financial
performance.
In a complex and uncertain world this may seem like a
simple equation – safe and reliable operations plus cost
discipline is good for the bottom line. But it works and the
numbers prove this.
We plan for the long term and we also measure our
progress year on year and quarter by quarter.
We were disappointed that we had to increase the
provision relating to claims associated with the Gulf of
Mexico spill, although we made real progress during the
year in our efforts to close out the remaining claims. The
claims facility is now winding down although a number of
claims remain to be resolved.
Our five-year plan
As I said, last year we set out our strategic priorities.
Simply put, these are designed to meet the dual
challenge: to produce more of the affordable energy that
the world needs while producing and delivering it in new
ways, with fewer emissions, that society wants.
The key to this dual challenge is to recognize that this
is not just a race to renewables, it’s a race to lower
greenhouse gas emissions. So, while we are fully
committed to the energy transition that is underway, we
also see a lot of uncertainty around the pace and path of
how this will unfold.
Our aim is to build a strong and flexible strategy with a
high-quality portfolio and the ability to adapt quickly as
the pace and path become clearer.
That means in the Upstream we are focused on growing
oil and gas in a way that offers us advantages in terms of
margin and value, with the reduced emissions in mind.
In the Downstream we continue to develop advantaged
manufacturing and marketing businesses that can create
value from existing, new and emerging markets.
Above: Chairing the panel of
the Oil and Gas Climate Initiative
meeting in London.
8
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We are preparing for a low carbon future by investing
in new companies and technologies across BP while
also leveraging knowledge from the development of our
existing Alternative Energy businesses.
And we are modernizing how BP works, using
technology and data to work more efficiently and
digitizing our processes.
Disciplined execution in 2017
We said that 2017 would be a very important year for BP.
We set out ambitious plans for the year and we delivered
on them.
We promised to start up seven major projects in the
Upstream. We brought these online and under budget for
the portfolio as a whole. These projects, along with the
six we brought online in 2016, have contributed to a 12%
increase in our production. That helps to put us on track
to deliver 900,000 barrels of new production per day by
2021. We also strengthened our portfolio with our most
successful year of exploration since 2004, sanctioned
three exciting new projects in Trinidad, India and the Gulf
of Mexico and added 143% reserves replacement for the
group.
In the Downstream we promised to grow earnings. In
fact, we had our best ever year, with a replacement cost
profit of $7.2 billion, driven by strong earnings growth in
our marketing and manufacturing businesses. This came
from volume growth in our premium fuels and lubricants,
the growth of our successful convenience retail
partnerships around the world and strong performance in
manufacturing.
Exciting growth opportunities
This is a time of transformational change for our industry.
An era of abundant resources and a changing fuel mix
mean that we must be competitive today and adapt fast
to change for tomorrow. So, we must modernize how we
work, embrace new advanced technologies and maintain
our downward pressure on costs. We are already in
action across BP.
In the Upstream we are growing gas and advantaged
oil on many fronts: signing a 25-year extension to our
ACG production-sharing agreement in Azerbaijan;
strengthening our relationship with Petrobras and
accessing the prolific Santos basin in Brazil; extending
our innovative alliance with Kosmos in West Africa;
growing in Norway though our Aker BP joint venture; and
adding production from onshore Abu Dhabi following the
deepening of our long-term strategic relationship with
the Abu Dhabi National Oil Company (ADNOC) at the
end of 2016.
In the Downstream we are building competitively
advantaged businesses; extending our differentiated
retail fuels offer in material new markets such as Mexico,
India, Indonesia and China; entering into a new joint
venture with DongMing Petrochemical as part of a
focused growth strategy in China; renewing and creating
new partnerships in lubricants with Renault Nissan, Ford,
VW and Volvo.
At the same time, we must look to produce and deliver
energy in new ways, with fewer emissions, to help
meet the world’s climate goals. At BP we have been
working on this challenge for over two decades and that
has informed our approach today: working to reduce
emissions in our operations; improving the products our
customers use to help them reduce their emissions;
creating new low carbon businesses and offers that
complement our existing portfolio.
In the low carbon space, we entered into a new
partnership with Lightsource, a global leader in the
development, acquisition and long-term management
of large-scale solar projects. In new ventures, we have a
pipeline of more than 40 active investments with more
than 200 partners looking to exploit opportunities in
advanced mobility, bio products, carbon management
and low carbon power and storage.
These are a few examples that I believe show we are in
great shape to act where we see opportunity to make a
real difference to this transition and, at the same time,
create value for our shareholders.
Strength in relationships
The world is changing fast and there is a lot of
uncertainty of what the future will actually look like. To
stay competitive a company needs to be in tune with
society. While we are making progress with issues such
as gender and ethnicity representation, we recognize we
still have more to do. Beyond having the right strategy,
to succeed and thrive in uncertainty requires strong and
trusting relationships. I am grateful to our partners, host
governments and other stakeholders who have stood
by us in hard times and continue to work with us to help
shape our future and the future energy landscape.
I am also grateful to you, our shareholders who have
shown great patience while we stabilized BP and built up
our resilience. I hope you see our recent performance as
signs that this patience is being rewarded.
And last, but not least, I want to thank the global BP
team. I don’t believe there is another company of our
size and scale that can adapt and manage change better
than we can. This spirit of invention and purpose has
been alive across BP for over a century and will carry us
forward into what, I believe, is a very bright future.
Bob Dudley
Group chief executive
29 March 2018
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95.3%
refining availability
94.7%
Upstream plant
reliability
Above: At the inauguration of
the first phase of development
of Oman’s giant Khazzan gas
field.
More information
Strategy
Page 12
Group performance
Page 21
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BP Annual Report and Form 20-F 2017
See Glossary
9
The changing world of energy
The world of energy is changing every
day. With rising concerns about climate,
technological advances and geopolitical
shifts, the energy mix is moving towards
lower carbon sources.
2040 outlook
Growing demand for energy
People rely on energy for heat, light and mobility.
Growing economies need energy to support their
industry and infrastructure. How that energy is delivered
is changing rapidly and the energy mix of the future will
become increasingly lower carbon.
The demand for energy continues to grow – largely
driven by rising incomes in emerging economies and
a global population heading towards nine billion by
2040. But this growth is much slower than in the
previous 20 years. The extent of the increase is being
curbed by gains in energy efficiency, as there is
greater attention around the world on using energy
more sustainably.
a
Energy consumption by region
(billion tonnes of oil equivalent)
2040
2020
2000
0
3
6
9
12
15
18
OECD
China
Other Asia
Africa
a Evolving transition scenario.
India
Rest of World
Energy mix is shifting
Today, oil and gas account for almost 60% of all energy
used. Even in a scenario that is consistent with the Paris
goals of limiting warming to less than 2ºC, oil and gas
could provide around 40% of all energy used by 2040.
So it’s essential that action is taken to reduce emissions
from their production and use.
In a low carbon world, gas offers a much cleaner
alternative to coal for power generation and a valuable
back-up for renewables, for example when the sun
and wind aren’t available. Gas also provides heat for
industry and homes and fuel for trucks and ships.
• To meet the rising demand for cleaner energy,
we are increasing our gas production.
Renewables are the fastest-growing energy source
and could account for at least 14% of all energy in 2040.
• We are building up our renewable portfolio – focusing
on biofuels, biopower, wind energy and solar energy.
Oil is the primary fuel for transport today. We expect its
share of the total energy mix will gradually decline as we
see more energy efficiency in traditional engines, greater
use of biofuels and gas, and growth in fully electric and
hybrid vehicles, as well as ride sharing, in the years
ahead.
• We are developing new efficient fuels and lubricants
that can help our customers and consumers to lower
their emissions.
Advances in technology
Insights from our Energy Outlook and Technology
Outlook help shape our strategic thinking. We consider
how policy, consumer behaviour and advances in
technology could affect the pace of the energy transition
and how we produce and use energy in the coming
decades.
• 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 Innovation in BP on page 44.
Above: Our Ituiutaba sugar cane processing unit in Brazil.
10
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Emerging greenhouse gas policy and
regulation
Governments are putting in place taxes, carbon trading
schemes and other measures to limit greenhouse gas
(GHG) emissions. A fifth of the world’s GHG emissions
are now covered by carbon pricing systems, double the
coverage from just five years ago. We expect around two
thirds of BP’s direct emissions will be in countries subject
to emissions and carbon policies by 2020. And we have
been active as a trader in the world’s current emissions
trading systems since their inception.
To help anticipate greater regulatory requirements
affecting our GHG emissions, we use a carbon cost
when evaluating our plans 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.
• 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.
Energy consumption – 2040 projections
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80-90%
CO2 emissions
Around 80-90% of carbon dioxide emissions from oil and gas products are
from their use by consumers in transportation, power plants, industries and
buildings. So one of the biggest contributions we can make to advance the energy
transition is by providing products and services that help consumers lower their
carbon footprint.
2016 Actual energy mix
2040 Evolving transition
2040 Faster transition
2040 Even faster transition
%
3
3
%
7
2
%
5
2
%
2
2
%
4
2
%
8
2
%
4
%
7
%
4
%
6
2
%
1
2
%
5
%
7
%
4
1
%
2
2
%
3
1
%
7
%
8
%
9
1
%
0
1
%
8
%
8
%
5
2
%
3
3
0
12
6
Billion tonnes of oil equivalent. The sum of the fuel shares may not equal 100% due to rounding.
3
9
15
18
Oil
Gas
Coal
Nuclear
Hydro
Renewables
Evolving transition
In this scenario, government policies,
technology and social preferences evolve in a
manner and speed seen in the recent past. The
growing world economy requires more energy
but consumption increases less quickly than
in the past.
Faster transition
This scenario sees carbon prices rising faster
than in the evolving transition scenario with
other policy interventions encouraging more
rapid energy efficiency gains and fuel
switching.
Even faster transition
This scenario matches carbon emissions
similar to the International Energy Agency’s
sustainable development scenario which
aims to limit the global temperature rise
to well below 2°C.
More information
BP Energy Outlook
Provides our projections of future energy trends
and factors that could affect them out to 2040.
See bp.com/energyoutlook
Technology Outlook
Describes how technology could influence the way
we meet the energy challenge into the future.
See bp.com/technologyoutlook
BP Annual Report and Form 20-F 2017
11
Book 1.indb 11
03/04/2018 16:40:05
Our strategy
Our industry is changing at a pace
not seen in decades. Oil, gas 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. Our strategy
allows us to be competitive at a time when
prices, policy, technology and customer
preferences are evolving.
We believe having a balanced portfolio
with advantaged oil and gas, competitive
downstream and low carbon activities,
as well as a dynamic investment strategy
give us resilience.
With the experience we have, the portfolio
we have created and the flexibility of
our strategy, we can embrace the energy
transition in a way that enhances our
investor proposition, while meeting
the need for energy today.
Growing gas and
advantaged oil in
the upstream
Invest in more gas and
oil, producing both with
increasing efficiency.
Major project start-ups
Started up seven major projects , making a
significant contribution to the 900,000 barrels
per day of expected new production by 2021.
Exploration successes
Made six potentially commercial discoveries
– two in the UK, two in Trinidad, one in Egypt
and one in Senegal with our partner Kosmos
Energy.
Key highlights
See page 27
Seismic success
Found significant additional oil resources at
our Atlantis field in the Gulf of Mexico using
a new seismic imaging technique.
Enduring relationships
Extended our contract in the Azeri-Chirag-
Gunashi field in Azerbaijan for a further 25
years, continuing our long-term advantaged
oil production.
More information
Financial framework
How this underpins our
commitment to sustain the
dividend for our shareholders.
See page 25
12
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BP Annual Report and Form 20-F 2017
Market-led growth
in the downstream
Venturing and
low carbon across
multiple fronts
Modernizing
the whole group
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Innovate with advanced
products and strategic
retail partnerships.
Pursue new opportunities
to meet evolving technology,
consumer and policy trends.
Simplify our processes and
enhance our productivity
through digital solutions.
Convenience partnerships
Continued the rollout of our convenience
partnership model across our retail network –
adding more than 220 sites in 2017, bringing
the total to 1,100.
Advancing biofuel technology
Acquired the Nesika ethanol plant in Kansas,
with joint venture partner DuPont, to
commercialize Butamax® bio-isobutanol
technology.
Automating well construction
Launched DrillPlan® – a new technology
to automate the entire well construction
process – at our Khazzan field in Oman,
in partnership with Schlumberger.
Retail sites in Mexico
Became the first global brand to enter
the Mexican retail fuels market since
deregulation – opening more than 120
BP-branded retail sites during the year.
Investing in artificial intelligence
Invested in AI software for the oil and gas
industry with venture partner Beyond Limits.
Serving customers digitally
Launched a range of digital apps to
enhance our customers’ experiences,
such as BPMe and in partnership with
TomTom Telematics, BP FleetMove.
Speedier solutions
Began a multi-year project to move
our electronic information from
physical data centres to the cloud.
See page 33
See page 46
Lower carbon products
Expanded our lower carbon products
portfolio with Castrol EDGE BIO-SYNTHETIC
now available in the US, the supply of jet
biofuel in Sweden and Norway, and our PTAir
brand – now available globally.
High-quality lubricants
Announced plans to build a high-quality
lubricants blend plant in China.
Renewable gas
Acquired Clean Energy’s renewable
natural gas business – giving BP access to its
network of gas transport customers and
helping to make biogas, made from organic
waste, more accessible to natural gas
powered vehicle fleets.
Generating solar energy
Partnered with Lightsource – Europe’s largest
solar development company – to help propel
its continuing and rapid expansion worldwide.
See page 23
Carbon trading
Used our powerful market insights and
innovative platforms to help generate over
12 million tonnes of CO2 reductions through
carbon offsetting projects to help customers
meet their emissions commitments.
Book 1.indb 13
03/04/2018 16:40:31
BP Annual Report and Form 20-F 2017
See Glossary
13
A year of delivery
This was a big year for BP with seven
major projects coming onstream, making
it one of the most significant years for
commissioning new projects in our history.
This puts us well on the way to achieving our
aim of 900,000 barrels of oil equivalent per
day of new production from our new major
projects by 2021.
1 Egypt: Taurus and Libra
• Production around 20% above plan.
• Added significant gas production
to the Egyptian market.
Fast facts
Operator
Partners
Project type
BP
BP (82.75%)
RWE Dea (17.25%)
Conventional gas
Peak annual average
production
~105mboe/d (gross)
~80mboe/d (net)
1 Taurus and Libra
2 Trinidad onshore
compression (TROC)
3 Quad 204
4 Persephone
5 Juniper
6 Khazzan Phase 1
7 Zohr
BP and its partners
operate across
55,000km2
in Egypt – about
the size of Croatia
100% of the gas
from the project
will be used for
the national grid
2 Trinidad: TROC
• Increased production from low-pressure wells in our
existing acreage in the Columbus Basin.
• This onshore facility has the capacity to deliver nearly
200 million standard cubic feet of gas per day when
fully operational.
+50 years
as largest contributor
to natural gas
production in
Trinidad
Fast facts
Operator
Partners
Atlantic LNG
100% owned by BP Trinidad and
Tobago which is owned by BP (70%)
and Repsol (30%)
Project type
Liquefied natural gas
Peak annual average
production
~35mboe/d (gross)
~35mboe/d (net)
14
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BP Annual Report and Form 20-F 2017
Book 1.indb 14
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3 UK North Sea: Quad 204
• Extended the lives of the Schiehallion
and Loyal fields out to 2035 and
beyond.
• Constructed and installed Glen Lyon,
the world’s largest harsh-water floating
production, storage and offloading
vessel.
• Progressed BP’s aim to double
UK North Sea production by 2020.
£2bn+
contracts awarded
to UK companies
Fast facts
Operator
Partners
BP
BP (36%)
Shell (54%)
Siccar Point Energy (10%)
Project type
Conventional oil
Peak annual average
production
~125mboe/d (gross)
~45mboe/d (net)
Quad 204 is expected
to return the fields to
their historical peak
production
4 Australia: Persephone
• Increased gas production from
the North West Shelf project
– Australia’s largest oil and
gas resource development.
• The North West Shelf project
contributes around a third of
Australia’s oil and gas production.
Fast facts
Operator
Partners
Woodside
BP (16.67%)
BHP, Chevron,
Shell, Woodside and
Mitsubishi-Mitsui (16.67% each)
Project type
Liquefied natural gas
Peak annual average
production
~50mboe/d (gross)
~8mboe/d (net)
Book 1.indb 15
03/04/2018 16:40:49
BP Annual Report and Form 20-F 2017
15
5 Trinidad: Juniper
• Our first subsea field development in
Trinidad.
• We expect Juniper will make a significant
contribution to Trinidad & Tobago’s national
gas production.
Fast facts
Operator
Partners
BP
100% owned by BP Trinidad
and Tobago, which is owned
by BP (70%) and Repsol (30%)
Project type
Liquefied natural gas
Peak annual average
production
~95mboe/d (gross)
~95mboe/d (net)
One of the biggest tight
gas projects in the
Middle East
It weighs about
10,000 tons
– equivalent to 20
Boeing 747s fully
loaded for take off
6 Oman: Khazzan Phase 1
• Accessed gas in extremely hard
rock at depths of up to 5km using
expertise from our US Lower 48
business.
• Conducted the world’s largest
onshore seismic survey and
3D modelling of the subsurface.
• Designed to be inherently
efficient and lower in
greenhouse gas emissions.
Fast facts
Operator
Partners
BP
BP (60%)
Oman Oil (40%)
Project type
Tight gas
Peak annual average
production
~172mboe/d (gross)
~103mboe/d (net)
16
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7 Egypt: Zohr
• Started up in less than two and a half years
from discovery – a record time for a field
of this size in deepwater.
• Thought to be the largest gas discovery
in the Mediterranean.
Fast facts
Operator
Partners
Project type
ENI
BP (10%)
Eni (60%)
Rosneft (30%)
Dry gas
Peak annual average
production
~364mboe/d (gross)
~36mboe/d (net)
More information
Go to youtube.com/bp to watch the
stories behind our seven major projects.
~1.3 billion
barrels of proved
reserves
BP’s net share from our seven major projects at peak production
(in thousand barrels of oil equivalent per day)
80
35
45
8
95
103
36
Taurus and Libra
TROC
Quad 204
Persephone
Juniper
Khazzan Phase 1
Zohr
Looking ahead
We plan to start-up
six projects in 2018.
1 2 Egypt
5 US
3 UK North Sea
6 Russia
4 Azerbaijan
More information
Upstream project pipeline
See page 30
BP Annual Report and Form 20-F 2017
17
Book 1.indb 17
03/04/2018 16:41:02
Measuring our progress
We assess our performance
across a wide range of
measures and indicators.
Our key performance indicators (KPIs)
provide a balanced set of metrics that give
emphasis to both financial and non-
financial measures. These help the board
and executive management assess
performance against our strategic priorities
and business plans, with non-financial
metrics playing a useful role as leading
indicators of future performance. BP
management uses these measures to
evaluate operating performance and make
financial, strategic and operating decisions.
Changes to KPIs
We have added Upstream plant
reliability to our KPIs this year to reflect
our strategy and align the measures
used for Upstream and Downstream. It
will also be used to assess performance
for the annual bonus in our 2018
remuneration outcomes assessment.
We no longer report loss of primary
containment as we are focusing on
more comparable industry metrics.
And in light of our refreshed strategy,
announced in February 2017, we’ve
updated the employee survey questions
to reflect our new priorities and retired
the group priorities index, which was
based on priorities set in 2012.
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.
Underlying replacement cost profit
($ billion)
REM
Operating cash flow ($ billion)
REM
3.4
6.2
0.1
2.6
5.9
3.8
(6.5)
2017
2016
2015
2014
2013
0
Profit (loss) for the year
Underlying RC profit for the year
12.1
13.4
23.5
is a useful measure for investors
Underlying RC profit
because it is one of the profitability measures BP management
uses to assess performance. It assists management in
understanding the underlying trends in operational
performance on a comparable year-on-year basis.
It reflects the replacement cost of inventories sold in the period
and is arrived at by excluding inventory holding gains and losses
from profit or loss. Adjustments are also made for
non-operating items and fair value accounting effects .
2017 performance Profit for the year and underlying RC profit
reflect higher oil and gas prices, and a stronger refining
environment compared with 2016, as well as the benefit
of major project start-ups, and stronger refining operational
performance.
2017
2016
2015
2014
2013
10.7
24.1
18.9
17.6
20.3
19.1
21.2
21.1
32.8
32.8
Operating cash flow excluding Gulf of Mexico oil
spill paymentsa
Operating cash flow
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. We believe 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.
2017 performance Operating cash flow was higher due to
improved business results, including a more favourable price
environment and higher production as well as lower Gulf of
Mexico oil spill payments which amounted to $5.2 billion in 2017.
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
Production (mboe/d)
2017
2016
2015
2014
2013
4
4
4
2
6
REM
7
7
2017
2016
2015
2014
2013
3,595
3,268
3,239
3,141
3,230
6
8
3,200
3,400
3,600
We monitor the progress of our major projects to gauge
whether we are delivering our core pipeline of projects under
construction on time.
Projects take many years to complete, requiring differing
amounts of resource, so a smooth or increasing trend should
not be anticipated.
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.
Production is a useful measure for tracking how our major
projects are helping to grow our business. 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.
2017 performance BP’s total reported production including
Upstream and Rosneft segments was 10% higher than in 2016
due to the Abu Dhabi onshore concession renewal and major
project start-ups.
REM Measures used for the remuneration policy
approved by shareholders at the 2017 AGM.
2017 performance We started up seven major projects in
Australia, Egypt, the UK North Sea, Oman and Trinidad.
Measures for the annual bonus are
focused on safety, reliable operations
and financial performance.
Measures for performance shares are
focused on shareholder value, capital
discipline and future growth.
REM These measures were used for executive
remuneration under the terms of our
discontinued 2014-16 policy.
More information
Directors’ remuneration
Page 90
Reported recordable injury frequencyb
REM
REM
Tier 1 process safety eventsb
REM
REM
2017
2016
2015
2014
2013
0.22
0.21
0.24
0.31
0.31
2017
2016
2015
2014
2013
18
16
20
20
0.1
0.2
0.3
0.4
10
20
28
30
40
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.
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.
2017 performance We have seen a small increase in our RIF
compared with 2016. Improving safety in our operations is a
high priority and we are working on it right across the business.
2017 performance We have seen a slight increase in tier 1
process safety events, and we remain focused on our
systematic approach to safety management and assurance.
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.
18
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BP Annual Report and Form 20-F 2017
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03/04/2018 16:41:02
Total shareholder return (%)
REM
Return on average capital employed (%)
REM
REM
Reserves replacement ratio (%)
20.0
9.5
29.0
55.5
2017
2016
2015
2014
2013
2.8
5.8
5.5
2017
2016
2015
2014
2013
61
63
9.6
10.2
109
129
4
8
12
60
80
100
120
140
160
2017
2016
2015
2014
2013
(12.8)
(8.3)
(16.5)
(11.6)
-20
0
0
14.7
14.0
20
40
60
REM
143
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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.
2017 performance Reduced TSR reflects lower share price
growth in 2017 compared with 2016, while the dividend per
share was maintained at the same level.
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 295
for more information including the nearest GAAP equivalent
data.
In recent years, ROACE has been lower in the oil and gas
sector, due to the impact of lower oil prices on earnings and the
capital investment made during the preceding period of $100
per barrel oil prices.
2017 performance The 2017 increase in ROACE is due to a
stronger environment and improved business performance.
Proved reserves replacement ratio is the extent to which the
year’s production has been replaced by proved reserves added
to our reserve base.
The ratio is expressed in oil-equivalent terms and includes
changes resulting from discoveries, improved recovery and
extensions and revisions to previous estimates, but excludes
changes resulting from acquisitions and disposals. The ratio
reflects both subsidiaries and equity-accounted entities.
This measure helps to demonstrate our success in accessing,
exploring and extracting resources.
2017 performance The ratio was higher due to development
activity in Abu Dhabi and Rosneft, expansion of the Khazzan
development in Oman and extension of the ACG licence.
Upstream unit production costs ($/boe)
REM
Upstream plant reliability (%)
Refining availability (%)
REM
2017
2016
2015
2014
2013
7.11
8.46
10.46
12.75
13.16
2017
2016
2015
2014
2013
4
8
12
16
90
91.7
92
94.7
95.3
95.0
93.4
2017
2016
2015
2014
2013
94
96
98
90
92
94
95.3
95.3
94.7
94.9
95.3
96
98
The upstream unit production cost indicator shows how
supply chain, headcount and scope optimization impact cost
efficiency.
2017 performance The lower unit production costs in 2017
reflect further efficiency increases and the benefit of new
production start-ups.
BP-operated Upstream plant reliability is calculated as 100%
less the ratio of total unplanned plant deferrals divided by
installed production capacity.
2017 performance The slight decrease in 2017 plant reliability
was due in part to our new major projects ramping up, however
this was partly offset by solid performance across existing
assets.
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.
2017 performance Refining availability was similar to 2016,
reflecting continued strong operational performance in 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.
Greenhouse gas emissions
(million tonnes of CO2 equivalent)
Employee engagement (%)
Diversity and inclusionc (%)
2017
2016
2015
2014
2013
49.4
50.1
49.0
48.7
50.3
2017
2016
2015
2014
2013
73
73
71
73
73
20
40
60
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 Rosneft.
2017 performance The primary reasons for the overall
decrease include operational changes such as planned
shutdowns at several of our refineries for maintenance, and
actions taken by our businesses to reduce emissions in areas
such as flaring, methane and energy efficiency.
We conduct an annual employee survey to understand and
monitor levels of employee engagement and identify areas for
improvement.
2017 performance The overall employee engagement score
was up from two years ago, when we saw a decline that
coincided with the uncertainties of a low oil price environment.
2017
2016
2015
2014
2013
21
24
22
23
19
18
18
21
21
21
5
10
15
20
25
30
Women
Non UK/USd
Each year we report the percentage of women and individuals
from countries other than the UK and the US among BP’s
group leaders.
2017 performance While the percentage of our group leaders
who are women decreased slightly, the number of non-UK/US
people rose. We are developing mentoring, sponsorship and
coaching programmes to help more women advance.
c Relates to BP employees.
d Figures for 2013-16 have been amended.
BP Annual Report and Form 20-F 2017
See Glossary
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Global energy markets
Oil prices recovered in 2017, but averaged only
half the prices seen in 2011-13. While the market
continues to rebalance in the face of ongoing
co-ordinated OPEC and non-OPEC production
restraint, inventories remain above their recent
historical average.
The world economy grew at 3.1% in 2017, its fastest rate of growth
since 2011. This was significantly faster than the 2.4% seen in 2016
and slightly more than the average of nearly 3% over the past 20 years.
Growth in the OECD picked up to 2.4%, from just 1.7% in 2016,
benefiting from improvements in both consumption and investment
across all major regions, and a pick-up in global trade. The non-OECD
showed a similar broad-based improvement, growing by 4.3% in 2017,
compared with 3.8% in 2016.
Oil
Crude oil prices ($/bbl – quarterly average)
Brent dated
150
120
90
60
08
09
10
11
12
13
14
15
16
2017
Prices
Dated Brent crude oil prices averaged $54.19 per barrel in 2017 – the
first annual increase since 2012 but roughly half the average of over $110
seen in 2011-13. Prices drifted lower over the first half of the year before
rebounding, ending the year at their monthly high point, averaging $64
in December.
Consumptiona
Global consumption increased by 1.6 million barrels per day (mmb/d)
to 97.8mmb/d for the year (1.6%) – due to continued low oil prices
and a recovering world economy. Demand once again grew most rapidly
in Asia’s emerging economies (+1mmb/d), but OECD demand also
increased for a third consecutive year.
Productiona
Global oil production saw weak growth for a second consecutive year,
rising by just 0.4mmb/d. However, the source of global weakness was
different in 2017. After falling in 2016, non-OPEC production recovered
(+0.8mmb/d), led by the US. In contrast OPEC production declined
by 0.4mmb/d – the first decline since 2013 – as the group engaged
with certain non-OPEC producers to restrain output.
Inventoriesa
These changes resulted in global demand exceeding supply in 2017.
As a result, oil inventories in the OECD began to decline, although they
remained well above the recent historical range. At the end of November
OECD commercial inventories were roughly 100 million barrels less than
2016, but remained 90 million barrels above the five-year average.
More information
Prices and margins
Pages 26 and 32
The surplus relative to the five-year average was well below the peak of
366 million barrels seen in July 2016.
Natural gas
Natural gas prices ($/mmBtu – quarterly average)
Henry Hub
12
10
8
6
4
2
08
09
10
11
12
13
14
15
16
2017
Prices
Gas prices rebounded in all key markets in 2017, as global markets
tightened. Liquefied natural gas (LNG) supply increased more slowly
than expected, while LNG demand from China was unexpectedly
strong, and high coal prices supported gas prices in the power
generation sector.
Gas prices in the US averaged $3.11 per million British thermal units
(mmBtu), up by $0.65 compared with 2016 ($2.46). The Japanese spot
price rebounded to $7.13/mmBtu in 2017 from $5.72/mmBtu in 2016,
driven by stronger Asian LNG demand, notably from China but also
hub
Japan, Korea and Pakistan. The UK National Balancing Point
price was 44.95 pence per therm, 30% higher than in 2016 (34.63),
supported by increasing coal prices. Meanwhile pipeline outages
and cold weather put pressure on UK prices towards the end of 2017.
Broad differentials between regional gas prices have increased,
even though they remain at much lower levels than the peaks
observed in 2012 and 2013.
Consumptionb
Global consumption is estimated to have grown more rapidly in 2017
than in 2016. Strong growth in Asia, the Middle East and Africa offset
a decline in North American consumption, where higher gas prices
caused gas to lose market share to coal in the US power sector.
Meanwhile demand in core European markets was broadly stable. And
higher weather-related demand towards the end of the year boosted
global annual demand.
Productionb
Total gas production is estimated to have increased substantially in 2017,
in contrast to 2016, which had similar production to 2015. Significant
production increases were achieved in Australia – supported by the start
of new LNG trains , and in Russia.
Global LNG supply capacity expanded strongly in 2017, adding almost
three times as much new capacity as in 2016. Several trains came online
in the US, Australia, Russia and Malaysia.
a From IEA Oil Market Report, 13 February 2018 ©, OECD/IEA 2018.
b Based on BP estimates from the BP Energy Outlook.
20
See Glossary
BP Annual Report and Form 20-F 2017
Group performance
We had strong delivery and growth across BP in 2017,
enabling the company to get back into balance. The full-year
underlying result was more than double a year earlier and our
financial frame remains resilient. We recommenced share
buybacks during the fourth quarter with the intention to offset
any ongoing dilution from scrip dividends over time.
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In summary
$6.2bn
underlying replacement
cost (RC) profit
$24.1bn
operating cash flow excluding
Gulf of Mexico oil spill
payments a
(2016 $2.6 billion)
(2016 $17.6 billion)
$3.4bn
profit attributable to
BP shareholders
$18.9bn
operating cash flow
(2016 $115 million)
(2016 $10.7 billion)
Financial and operating performance
Segment RC profit (loss) before interest and tax
($ billion)
2017
2016
2015
(20)
(15)
(10)
(5)
0
5
10
15
20
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
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 (favourable) adverse impact of non-operating items and fair value
$ million
except per share amounts
2015
(7,918)
2016
(430)
(1,865)
2,467
(57)
115
(1,597)
483
(999)
(1,653)
3,171
(82)
(6,482)
1,889
(569)
(5,162)
2017
9,474
(2,294)
(3,712)
(79)
3,389
(853)
225
2,761
accounting effects , before tax
3,730
6,746
15,067
Taxation charge (credit) on non-operating items and fair value
accounting effects
Underlying replacement cost profit
Dividends paid per share – cents
– pence
a This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
b Profit (loss) attributable to BP shareholders.
(325)
6,166
40.0
30.979
(3,162)
2,585
40.0
29.418
(4,000)
5,905
40.0
26.383
More information
Upstream
Page 26
Downstream
Page 32
Rosneft
Page 38
Other businesses
and corporate
Page 41
Oil and gas disclosures
for the group
Page 259
BP Annual Report and Form 20-F 2017
See Glossary
21
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03/04/2018 16:41:10
Results
Profit for the year ended 31 December 2017 was $3.4 billion, compared
with $115 million in 2016. Excluding inventory holding gains,
replacement cost (RC) profit was $2.8 billion, compared with a loss of
$1.0 billion in 2016. After adjusting for non-operating items of $3.3 billion
and net adverse fair value accounting effects of $96 million (both on a
post-tax basis), underlying RC profit for the year ended 31 December
2017 was $6.2 billion, an increase of $3.6 billion compared with 2016.
The increase was predominantly due to higher results in both Upstream
and Downstream segments. The Upstream result reflected higher oil
and gas prices and increased production. The Downstream result
reflected strong refining performance, including an improved margin
environment and growth in fuels marketing.
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, RC loss was $1.0 billion, compared with a loss of $5.2 billion in
2015. After adjusting for non-operating items of $2.8 billion and net
adverse fair value accounting effects of $0.8 billion (both on a post-tax
basis), 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.
Non-operating items
The net charge for non-operating items was $3.6 billion pre-tax and $3.3
billion post tax in 2017. The post-tax non-operating charge includes a
charge of $1.7 billion recognized in the fourth quarter relating to business
economic loss and other claims associated with the Gulf of Mexico oil
spill and a $0.9 billion deferred tax charge following the change in the US
tax rate enacted in December 2017. In addition, the net charge also
reflects an impairment charge in relation to upstream assets.
The net charge for non-operating items of $5.7 billion pre-tax and $2.8 billion
post tax in 2016 mainly related to additional charges for the Gulf of Mexico
oil spill which were partially offset by net impairment reversals. Non-
operating items in 2016 also included a restructuring charge of $0.8 billion
(2015 $1.1 billion).
More information on non-operating items and fair value accounting
effects can be found on pages 250 and 294. See Financial statements
– Note 2 for further information on the impact of the Gulf of Mexico oil
spill on BP’s financial results.
Taxation
The charge for corporate income taxes in 2017 includes a one-off
deferred tax charge of $0.9 billion in respect of the revaluation of
deferred tax assets and liabilities following the reduction in the US
federal corporate income tax rate from 35% to 21% enacted in
December 2017. The effective tax rate (ETR) on the profit or loss for the
year was 52% in 2017, 107% in 2016 and 33% in 2015. The ETR for all
three years was impacted by various one-off items.
Adjusting for inventory holding impacts, non-operating items which
include the impact of the US tax rate change, 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 38% in 2017 (2016 23%, 2015 31%). The
adjusted ETR for 2017 is higher than 2016 predominantly due to
changes in the geographical mix of profits, notably the impact of the
renewal of our interest in the Abu Dhabi onshore oil concession. The
adjusted ETR for 2016 was 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.
In the current environment, the adjusted ETR in 2018 is expected to be
above 40%.
Cash flow and net debt information
Operating cash flow excluding
Gulf of Mexico oil spill
paymentsa
Operating cash flow
Net cash used in investing
activities
Net cash provided by (used in)
2017
2016
$ million
2015
24,098
18,931
17,583
10,691
20,263
19,133
(14,077)
(14,753)
(17,300)
financing activities
(3,296)
1,977
(4,535)
Cash and cash equivalents at
end of year
25,586
23,484
26,389
Capital expenditure b
Organic capital expenditure
Inorganic capital expenditure
Gross debt
Net debt
Gross debt ratio (%)
Net debt ratio (%)
(16,501)
(1,339)
(17,840)
63,230
37,819
38.6%
27.4%
(16,675)
(777)
(17,452)
58,300
35,513
37.6%
26.8%
N/A
N/A
(20,202)
53,168
27,158
35.1%
21.6%
a This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
b From 2017 onwards we are reporting organic, inorganic and total capital expenditure on a
cash basis which were previously reported on an accruals basis. This aligns with BP's
financial framework and is now consistent with other financial metrics used when comparing
sources and uses of cash. An analysis of capital expenditure on a cash basis for 2015 is not
available.
Operating cash flow
Net cash provided by operating activities for the year ended
31 December 2017 was $18.9 billion, $8.2 billion higher than the
$10.7 billion reported in 2016. Operating cash flow in 2017 reflects
$5.3 billion of pre-tax cash outflows related to the Gulf of Mexico oil spill
(2016 $7.1 billion). Compared with 2016, operating cash flows in 2017
were impacted by improved business results, including a more
favourable price environment and higher production, working capital
effects, and a $2.5 billion increase in income taxes paid.
Movements in inventories and other current and non-current assets and
liabilities adversely impacted cash flow in the year by $3.4 billion. There
was an adverse impact on working capital from the Gulf of Mexico oil
spill of $5.2 billion. Other working capital effects, arising from a variety of
different factors had a favourable effect of $1.8 billion. Receivables and
inventories increased during the year principally due to higher oil prices.
The effect of this on operating cash flow was more than offset by a
corresponding increase in payables. BP actively manages its working
capital balances to optimize cash flow.
There was a decrease in net cash provided by operating activities of
$8.4 billion in 2016 compared with 2015, of which $6.0 billion related to
higher pre-tax cash outflows associated with the Gulf of Mexico oil spill.
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 2016 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. Inventories increased during 2016
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.
22
See Glossary
BP Annual Report and Form 20-F 2017
Modernizing
the whole group
Speedier
solutions
Activity on
7,000
servers in four
datacentres moving
to the cloud
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From our headquarters in
London to the underwater
facilities in Western Australia
– our modernization
programme is transforming
how we work across BP.
We are simplifying how we operate to
create a more agile organization and
working to change mindsets so that
they fit the increasingly competitive and
margin-dependent industry. At the
same time, we're digitizing and
automating more of our work.
We are in the process of systematically
migrating our vast amounts of data from
physical centres to the cloud,
embracing the agility and power of
cloud technologies, while maintaining
necessary levels of data security.
We have already moved our corporate
website to Amazon Web Services®, and
we now plan to close all our physical
datacentres over several years, fully
embracing the agility and power of
cloud technologies.
Microsoft Azure® is intended to become
a group-wide platform for collaboration
and data analytics, with services such
as visualization and predictive tools
to help us analyse data, gain insights
and make decisions faster.
We are also piloting the use of
blockchain database technology in our
oil and gas trading business to help
increase efficiency in terms of speed
and verification of transactions.
Blockchain is a digital ledger system
that records online transactions and
helps to streamline financial processes
and cut back office costs.
Book 1.indb 23
03/04/2018 16:41:15
BP Annual Report and Form 20-F 2017
23
Net cash used in investing activities
Net cash used in investing activities for the year ended 31 December
2017 decreased by $0.7 billion compared with 2016.
The decrease mainly reflected an increase of $0.8 billion in
disposal proceeds.
The decrease of $2.5 billion in 2016 compared with 2015 reflected a
reduction in cash outflow in respect of capital expenditure, including
investment in joint ventures and associates , of $2.8 billion. The
reduction in cash capital expenditure in 2016 reflected the group’s
response to the lower oil price environment.
There were no significant cash flows in respect of acquisitions in 2017,
2016 and 2015.
The group has had significant levels of capital investment for many
years. Total capital expenditure for 2017 was $17.8 billion (2016 $17.5
billion), of which organic capital expenditure was $16.5 billion (2016
$16.7 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. We expect organic capital
expenditure to be in the range of $15-16 billion in 2018.
Disposal proceeds for 2017 were $3.4 billion (2016 $2.6 billion, 2015
$2.8 billion), including amounts received for the disposal of our interest
in the SECCO joint venture. In addition, we received $0.8 billion in
relation to the initial public offering of BP Midstream Partners LP’s
common units, shown within financing activities in the cash flow
statement, and total proceeds for the year were $4.3 billion. In 2016
disposal proceeds included amounts received for the sale of certain
midstream assets in the Downstream fuels business and our Decatur
petrochemicals complex. In addition, we 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. We expect disposal proceeds to be
in the range of $2-3 billion in 2018.
Net cash used in financing activities
Net cash used in financing activities for the year ended 31 December
2017 was $3.3 billion, compared with $2.0 billion provided by financing
activities in 2016. This was mainly the result of a reduction of $3.5 billion
in net proceeds from financing. The total dividend paid in cash in 2017
was $1.5 billion higher than in 2016, see below for further information.
In 2016 the net cash provided by financing activities reflected 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 described above. The total
dividend paid in cash in 2016 was $2.1 billion lower than in 2015
– see below for further information.
Total dividends distributed to shareholders in 2017 were 40.00 cents
per share, the same as 2016. This amounted to a total distribution
to shareholders of $7.9 billion (2016 $7.5 billion, 2015 $7.3 billion), of
which shareholders elected to receive $1.7 billion (2016 $2.9 billion,
2015 $0.6 billion) in shares under the scrip dividend programme.
The total amount distributed in cash amounted to $6.2 billion during
the year (2016 $4.6 billion, 2015 $6.7 billion).
Debt
Gross debt at the end of 2017 increased by $4.9 billion from the end of
2016. The gross debt ratio at the end of 2017 increased by 1%. Net
debt at the end of 2017 increased by $2.3 billion from the 2016 year-end
position. The net debt ratio at the end of 2017 increased by 0.6%.
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 25 for gross debt, which is the nearest equivalent
measure on an IFRS basis, and for further information on net debt.
Cash and cash equivalents at the end of 2017 were $2.1 billion higher
than 2016.
For information on financing the group’s activities, see Financial
statements – Note 27 and Liquidity and capital resources on page 251.
Group reserves and production (including Rosneft segment)a
2017
2016
2015
Estimated net proved reserves
(net of royalties)
Liquids (mmb)
Natural gas (bcf)
Total hydrocarbons (mmboe)
Of which:
Equity-accounted entitiesb
Production (net of royalties)
Liquids (mb/d)
Natural gas (mmcf/d)
Total hydrocarbons (mboe/d)
Of which:
Subsidiaries
Equity-accounted entitiesc
10,672
45,060
18,441
10,333
43,368
17,810
9,560
44,197
17,180
8,949
8,679
7,928
2,260
7,744
3,595
2,164
1,431
2,048
7,075
3,268
1,939
1,329
2,007
7,146
3,239
1,969
1,270
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 38 and Supplementary information
on oil and natural gas on page 191 for further information.
c Includes BP’s share of Rosneft. See Rosneft on page 38 and Oil and gas disclosures
for the group on page 259 for further information.
Total hydrocarbon proved reserves at 31 December 2017, on an
oil-equivalent basis including equity-accounted entities, increased by
4% compared with 31 December 2016. The change includes a net
increase from acquisitions and disposals of 47mmboe (increase of
90mmboe within our subsidiaries, decrease of 43mmboe within our
equity-accounted entities). Acquisition activity in our subsidiaries
occurred in Egypt, the US and the UK, and divestment activity in our
subsidiaries was in the UK. In our equity-accounted entities, acquisitions
occurred in Aker BP and Rosneft and divestments occurred in Aker BP
and in Pan American Energy.
Our total hydrocarbon production for the group was 10% higher
compared with 2016. The increase comprised a 12% increase (12%
increase for liquids and 11% increase for gas) for subsidiaries and
an 8% increase (9% increase for liquids and 5% increase for gas)
for equity-accounted entities.
Above: On board Glen Lyon, our floating production storage and offloading vessel in the
UK North Sea.
24
See Glossary
BP Annual Report and Form 20-F 2017
Book 1.indb 24
03/04/2018 16:41:22
Focused on delivering competitive returns
BP’s financial framework
underpins our commitment
to sustain the dividend
for our shareholders. We
have been meeting those
expectations each year.
Our financial framework
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.
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Principle
22022 117 aaaachhievveemeentnt
2020181 gguidadaaance
Looking ahead – 2019 to 2021
Optimize capital
expenditure
Make selective
divestments
Organic capital expenditure a
was $16.5 billion*. This was
within our original guidance of
$15-17 billion.
Total divestment and other
proceeds of $4.3 billionb achieved.
This was just under our
expected guidance of
$4.5-5.5 billion for the year.
We expect organic capital
expenditure of $15-16 billion.
We expect organic capital
expenditure of $15-17 billion
per year.
We expect divestments
of $2-3 billion.
We expect $2-3 billion of
divestments per year.
Payments related to the
Gulf of Mexico oil spill
2017 payments totalled
$5.2 billion.
Maintain flexibility
around gearing
Gearing at the end of 2017
was 27.4%** within our target
range.
We expect just over
$3 billion of cash payments.
We expect around $2 billion in
2019, then stepping down to
around $1 billion per year.
Within the 20-30% band.
Within the 20-30% band.
Group return on average
capital employed (ROACE)
ROACE was 5.8%***.
Further improvement.
We are aiming to exceed
10% by 2021 at real oil
prices around $55/barrel.
a From 2017 onwards we are reporting organic, inorganic and total capital expenditure on a cash basis, which were previously reported on an accruals basis. This aligns with BP's financial
framework and is now consistent with other financial metrics used when comparing sources and uses of cash.
b This includes proceeds of $0.8 billion received in relation to the initial public offering of BP Midstream Partners LP’s common units. Divestment proceeds for 2017 were $3.4 billion.
Balancing our sources and uses of cashc
We rebalanced organic sources and uses of
cash in 2017 – operating cash flow excluding
Gulf of Mexico oil spill payments exceeded
organic capital expenditure, cash dividend
payments to BP shareholders and share
buybacks by $1.1 billion. This was achieved at
an average Brent oil price of $54 per barrel.
Nearest GAAP equivalent measures
* Capital expenditure : $17.8 billion.
** Gross debt ratio: 38.6%.
*** Numerator: Profit attributable to BP shareholders $3.4 billion;
Denominator: Average capital employed $159.4 billion.
Organic sources and uses of cash ($ billion)
For the year ended 31 December
2017
2016
28
24
20
16
12
8
4
28
24
20
16
12
8
4
Sources
Uses
Sources
Uses
Other sources and uses of cash ($ billion)
For the year ended 31 December
2017
12
8
4
2016
12
8
4
Sources
Uses
Sources
Uses
Organic sources
Organic uses
Operating cash flow excluding Gulf of
Mexico oil spill payments
Others
Organic capital expenditure
Cash dividends paid
Share buyback
Other sources
Divestment and other proceedsd
Other uses
Operating cash flow – Gulf of Mexico oil spill
Inorganic capital expenditure
c This does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
d 2017 includes proceeds of $0.8 billion received in relation to the initial public offering of BP Midstream Partners LP’s common units and 2016 includes proceeds of $0.6 billion received in
relation to the sale of 20% from our shareholding in Castrol India Limited. These proceeds are shown within financing activities in the cash flow statement.
BP Annual Report and Form 20-F 2017
See Glossary
25
Book 1.indb 25
03/04/2018 16:41:24
Upstream
2017 was a strong year of delivery, demonstrated by the
start-up of seven major projects. This shows we are creating
real value and tangible growth – with opportunities out to 2021
and beyond.
Bernard Looney, chief executive, Upstream
In summary
28,000km2 94.7% 6
new exploration access
BP-operated upstream
plant reliability
successful completion
of turnarounds
(2016 71,000km2)
(2016 95.3%)
(2016 11)
3
80.5% 2.5
final investment
decisions
BP-operated upstream
operating efficiency
(2016 5)
Business model
million barrels of oil equivalent
per day – hydrocarbon
production
(2016 2.2mmboe/d)
Upstream profitability ($ billion)
5.2
5.9
-0.5
-0.9
0.6
1.2
2017
2016
2015
2014
2013
8.9
15.2
16.7
18.3
Replacement cost (RC) profit (loss) before interest and tax
Underlying RC profit (loss) before interest and tax
The Upstream segment is responsible for our activities in oil and natural gas exploration, field development and production. We do this through five
global technical and operating functions:
Exploration
Global wells
organization
Global operations
organization
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.
Strategy
Our strategy has three parts and is enabled by:
Quality execution
We want to be the best at what we do –
everywhere we work. This starts with
executing our activity safely. In every basin,
we will benchmark against the competition
and aim to be the best – whether it be
operating facilities reliably and cost
effectively, with a focus on emissions, drilling
wells, managing our reservoirs, exploring,
building projects, or deploying technology.
Through the quality of our execution, scale
and infrastructure, we aim to be the low-cost
developer and producer in each basin, and
as a business, get more from a unit of capital
than our competitors.
Growing gas and advantaged oil
We will manage our portfolio through
disciplined investment in the world’s best oil
and gas basins. We plan to grow both oil and
gas production. Natural gas is a big lever for
reducing greenhouse gas emissions. This
means taking a leadership role in tackling the
challenge of methane. Around half of our
portfolio is currently gas and we expect this to
grow as we bring our major projects on line.
Our gas portfolio will be complemented by
advantaged oil assets – oil we can produce
at a higher margin or at a lower cost, creating a
portfolio that is resilient whatever the price
environment.
26
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BP Annual Report and Form 20-F 2017
Returns-led growth
We want to grow – but not at any cost.
We always look to grow returns and value.
We believe this growth will come from many
sources – production growth, expanding and
managing our margins, operational efficiency,
unit cost reduction, and capital efficiency with
disciplined levels of capital reinvestment.
Book 1.indb 26
03/04/2018 16:41:28
In addition to our core Upstream exploration, development and
production activities, the segment is responsible for midstream
transportation, storage and processing. We also market and trade
natural gas, including liquefied natural gas (LNG), power and natural
gas liquids (NGL). In 2017 our activities took place in 29 countries.
In 2016 we identified a future growth target of 900,000 barrels of oil
equivalent per day of production from new projects by 2021 and we
remain on track to deliver that. We expect this production to deliver 35%
higher operating cash margins on average than our 2015 upstream
assets, which supports our value over volume strategy.
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.
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.
We 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.
Growing gas and
advantaged oil
Largest contributor to natural
gas production in Trinidad
50+ years
Expanding gas
projects in Trinidad
Trinidad & Tobago is a key
contributor to BP's growing
gas portfolio and 2017 was a
pivotal year for our business
in the country.
We started up two major gas projects
in 2017: Juniper – our first subsea field
development in Trinidad and the area’s
largest project for several years, and
Trinidad onshore compression – the
first project of its kind in the region and
for BP.
And we completed the Sercan 2
field development – a joint venture
with EOG Resources. But these
are just the start.
We also made two significant gas
discoveries with our Savannah and
Macadamia exploration wells in
offshore Trinidad. This demonstrates
the benefit of our investment in
seismic technology, which is helping
us access the full potential of the
Columbus Basin.
Our next planned major project in
Trinidad is the development of the
Angelin natural gas field, which will
include construction of our fifteenth
offshore production facility in Trinidad.
We expect first gas in early 2019.
Extending the
life of our Galeota
terminal for
20+ years
15 million
tonnes per annum
capacity at our Atlantic
liquefaction plant
BP Annual Report and Form 20-F 2017
See Glossary
27
27
BP Annual Report and Form 20-F 2017Strategic report – performance Financial performance
Sales and other operating
revenuesa
RC profit (loss) before interest
and tax
Net (favourable) adverse impact
of non-operating items and
fair value accounting effects
Underlying RC profit (loss) before
interest and tax
Organic capital expenditure b
BP average realizationsc
Crude oild
Natural gas liquids
Liquids
Natural gas
US natural gas
Total hydrocarbons
Average oil marker pricese
Brent
West Texas Intermediate
Average natural gas
marker prices
Average Henry Hub gas pricef
Average UK National Balancing
2017
2016
$ million
2015
45,440
33,188
43,235
5,221
574
(937)
644
(1,116)
2,130
5,865
13,763
(542)
14,344
1,193
N/A
51.71
26.00
49.92
3.19
2.36
35.38
54.19
50.79
39.99
17.31
38.27
$ per barrel
49.72
20.75
47.32
$ per thousand cubic feet
3.80
2.10
$ per barrel of oil equivalent
35.46
2.84
1.90
28.24
43.73
43.34
$ per barrel
52.39
48.71
3.11
$ per million British thermal units
2.67
pence per therm
2.46
Point gas price e
44.95
34.63
42.61
a Includes sales to other segments.
b A reconciliation to GAAP information at the group level is provided on page 249. Organic
capital expenditure on a cash basis in 2015 is not available.
c Realizations are based on sales by consolidated subsidiaries only, which excludes
equity-accounted entities.
d Includes condensate and bitumen.
e All traded days average.
f 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
90
60
30
2017
2016
2015
Five-year range
Jan
Feb Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
The dated Brent price in 2017 averaged $54.19 per barrel. Prices drifted
lower over the first half of the year before rebounding, ending the year
at their monthly high point, averaging $64 in December. After falling in
2016, non-OPEC production recovered (+0.8mmb/d), led by the US. In
contrast OPEC production declined by 0.4mmb/d – the first decline
since 2013 – as the group engaged with certain non-OPEC producers to
restrain output.
Henry Hub ($/mmBtu)
9
6
3
2017
2016
2015
Five-year range
Jan
Feb Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
The 2017 Henry Hub First of Month Index price was higher than 2016
($2.46).
The UK National Balancing Point hub price was 44.95 pence per therm,
30% higher than in 2016 (34.63), supported by increasing coal prices.
Meanwhile pipeline outages and cold weather put pressure on UK
prices towards the end of 2017.
For more information on the global energy market in 2017 see page 20.
Financial results
Sales and other operating revenues for 2017 increased compared with
2016, primarily reflecting higher liquids realizations, higher production
and higher gas marketing and trading revenues. The decrease in 2016
compared with 2015 primarily reflected lower liquids and gas realizations
and lower gas marketing and trading revenues.
Above: Dolphin Island vessel overlooking our Atlantis platform in the Gulf of Mexico.
28
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BP Annual Report and Form 20-F 2017
Book 1.indb 28
03/04/2018 16:41:32
Replacement cost profit before interest and tax for the segment
included a net non-operating charge of $671 million. This primarily
relates to impairment charges associated with a number of assets,
following changes in reserves estimates, and the decision to dispose of
certain assets. See Financial statements – Note 4 for further information.
Fair value accounting effects had a favourable impact of $27 million
relative to management’s view of performance.
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.
New access in 2017
We gained access to new acreage covering almost 28,000km2 in eight
countries – Brazil, Canada, Côte D’Ivoire, Mauritania, Mexico, Senegal,
the UK and the US.
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The 2016 result included a net non-operating gain of $1,753 million,
primarily related 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. Fair value accounting effects had
an adverse impact of $637 million. 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.
After adjusting for non-operating items and fair value accounting effects,
the underlying replacement cost result before interest and tax was a
profit, compared with a loss in 2016. This improved result primarily
reflected higher liquids realizations, and higher production including the
impact of the Abu Dhabi onshore concession renewal and major
projects start-ups, partly offset by higher depreciation, depletion and
amortization, and higher exploration write-offs.
Compared with 2015 the 2016 result reflected significantly 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 benefits from simplification and efficiency activities,
lower exploration write-offs, lower depreciation, depletion and
amortization expense and lower rig cancellation charges.
Organic capital expenditure on a cash basis was $13.8 billion.
In total, disposal transactions generated $1.2 billion in proceeds in 2017,
with a corresponding reduction in net proved reserves of 10.6mmboe
within our subsidiaries. The major disposal transactions during 2017
were the disposal of 25% of our interest in the Magnus field in the UK
and a portion of our interests in the Perdido offshore hub in the US.
More information on disposals is provided in Upstream analysis by
region on page 253 and Financial statements – Note 3.
Outlook for 2018
• We expect to start up six new major projects in 2018.
• We expect underlying production to be higher than 2017. The actual
reported outcome will depend on the exact timing of project start-ups,
acquisitions and 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.
Exploration success
We participated in six potentially commercial discoveries in 2017
– Qattameya in Egypt, Macadamia and Savannah in Trinidad,
Yakaar-1 in Senegal, and Achmelvich and Capercaillie in the UK.
Exploration and appraisal costs
Excluding lease acquisitions, the costs for exploration and appraisal
were $1,655 million (2016 $1,402 million, 2015 $1,794 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 12% of exploration and appraisal costs were directed
towards appraisal activity. We participated in 41 gross (25.03 net)
exploration and appraisal wells in nine countries.
Exploration expense
Total exploration expense of $2,080 million (2016 $1,721 million,
2015 $2,353 million) included the write-off of expenses related to
unsuccessful drilling activities, lease expiration or uncertainties around
development in Angola ($729 million), Egypt ($368 million), the Gulf
of Mexico ($213 million) and others ($349 million), partially offset by
a net write-back of $56 million in block KG D6 in India (see Financial
statements – Note 6).
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 2017,
increased by 2% (an increase of 4% for subsidiaries and a decrease
of 12% for equity-accounted entities) compared with proved reserves
at 31 December 2016.
Proved reserves replacement ratio
The proved reserves replacement ratio for the segment in 2017 was
127% for subsidiaries and equity-accounted entities (2016 96%), 133%
for subsidiaries alone (2016 101%) and 78% for equity-accounted
entities alone (2016 61%). For more information on proved reserves
replacement for the group see page 259.
Upstream proved reserves (mmboe)
• We expect oil prices will continue to be challenging in the near term.
Total
Exploration
The group explores for oil and natural gas under a wide range of
licensing, joint arrangement
We may do this alone or, more frequently, with partners.
and other contractual agreements.
Our exploration and new access teams work to enable us to optimize
our resource base and provide us with a greater number of options.
Gas
3. Subsidiaries
4. Equity-accounted entities
Total
Liquids
1. Subsidiaries
2. Equity-accounted entities
4,447
692
5,139
5,045
392
5,437
4
3
1
2
Book 1.indb 29
03/04/2018 16:41:32
BP Annual Report and Form 20-F 2017
See Glossary
29
Gas
Oil
Type
Estimated net proved reserves (net royalties)a
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
2017
2016
2015
million barrels
4,129
674
4,803
318
18
336
4,447
692
5,139
29,263
2,274
31,537
9,492
1,085
10,577
3,778
771
4,549
373
16
389
4,151
787
4,938
3,560
694
4,254
422
13
435
3,982
707
4,689
billion cubic feet
30,563
2,465
33,027
28,888
2,580
31,468
million barrels of oil equivalent
9,252
1,132
10,384
9,131
1,232
10,363
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 2017
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 14 million barrels (16 million barrels at 31 December 2016 and 19 million barrels at
31 December 2015) in respect of the 30% non-controlling interest in BP Trinidad & Tobago
LLC.
e Includes 1,860 billion cubic feet of natural gas (2,026 billion cubic feet at 31 December 2016
and 2,359 billion cubic feet at 31 December 2015) in respect of the 30% non-controlling
interest in BP Trinidad & Tobago LLC.
Developments
We achieved seven major project start-ups in 2017: one in Australia,
two in Egypt, one in Oman, two in Trinidad, and one in the UK North Sea.
In addition to these, we made good progress on projects in AGT
(Azerbaijan, Georgia, Turkey), Egypt, the Gulf of Mexico, and the UK.
• Azerbaijan, Georgia, Turkey – the Shah Deniz Stage 2 project is now
almost 99% complete in terms of engineering, procurement,
construction and commissioning and remains on target for production
of first gas in 2018.
Our project pipeline
*BP operated
Project
2017 start-ups
Juniper*
Khazzan Phase 1*
Persephone
Trinidad onshore compression*
West Nile Delta Taurus/Libra*
Zohr
Quad 204*
Location
Trinidad
Oman
Australia
Trinidad
Egypt
Egypt
UK North Sea
Expected start-ups 2018-2021
Projects currently under construction
Angelin*
Atoll Phase 1*a
Culzean
KG D6 R-Series
Shah Deniz Stage 2*
Tangguh expansion*
West Nile Delta Giza/Fayoum*
Western Flank B
Clair Ridge*
Constellation
Mad Dog Phase 2*
Taas Expansion
Thunder Horse North West Expansion* US Gulf of Mexico
Trinidad
Egypt
UK North Sea
India
Azerbaijan
Indonesia
Egypt
Australia
UK North Sea
US Gulf of Mexico
US Gulf of Mexico
Russia
Expected start-ups 2018-2021
Design and appraisal phase
Cassia compression
KG D6 D55
KG D6 Satellites
Khazzan Phase 2*
Tortue Phase 1*
Alligin*
Atlantis Phase 3*
Vorlich*
Zinia 2
Trinidad
India
India
Oman
Mauritania and
Senegal
UK North Sea
US Gulf of Mexico
UK North Sea
Angola
• Egypt – work to achieve start-up of the Giza/Fayoum wells in late 2018
a Production commenced in early 2018.
is underway in the West Nile Delta with a revised scope and an
amended plan of development.
• Gulf of Mexico – the first development well on the Anadarko-
operated Constellation project was drilled and completed in 2017. First
production is expected in late 2018.
• UK – commissioning offshore is well underway at the Clair Ridge
development following completion of the construction phase in 2016.
First oil is expected in 2018.
Subsidiaries’ development expenditure incurred, excluding midstream
activities, was $10.7 billion (2016 $11.1 billion, 2015 $13.5 billion).
Beyond 2021
We have a deep hopper of projects that are currently under
appraisal. Our focus here is to ensure we maximize value 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: across six of the seven continents.
• a range of development types: from exploration to brownfield
and near-field.
30
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BP Annual Report and Form 20-F 2017
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Gas marketing and trading activities
Our integrated supply and trading function markets and trades our own
and third-party natural gas (including LNG), biogas, 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. We are expanding
our LNG portfolio, which includes global partnerships with utility
companies, gas distributors and national oil and gas companies, and in
2017 we supplied the first commercial LNG contact based on offshore
ship-to-ship transfer.
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 27 and the range of contracts used is
described in Glossary – commodity trading contracts on page 289.
Above: Smart glasses are used to share data with off-site technical experts at our
Lower 48 operations in Colorado.
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 2017, efficient delivery of turnarounds and strong infill
drilling performance, we have maintained base decline at less than
3% on average over the last five 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
Subsidiaries
Equity-accounted entitiesc
Natural gas liquids
Subsidiaries
Equity-accounted entitiesc
Total liquids
Subsidiaries
Equity-accounted entitiesc
Natural gas
Subsidiaries
Equity-accounted entitiesc
Total hydrocarbons
Subsidiaries
Equity-accounted entitiesc
2017
2016
2015
thousand barrels per day
1,064
199
1,263
85
8
93
1,149
207
1,356
5,889
547
6,436
943
179
1,122
82
4
86
1,025
184
1,208
933
165
1,099
88
7
95
1,022
172
1,194
million cubic feet per day
5,495
456
5,951
5,302
494
5,796
thousand barrels of oil equivalent per day
1,969
1,939
251
269
2,220
2,208
2,164
302
2,466
a Because of rounding, some totals may not agree exactly with the sum of their component parts.
b Includes condensate and bitumen.
c Includes BP’s share of production of equity-accounted entities in the Upstream segment.
Our total hydrocarbon production for the segment in 2017 was 11.7%
higher compared with 2016. The increase comprised an 11.6% increase
(12.1% for liquids and 11.1% for gas) for subsidiaries and a 12.2%
increase (12.9% for liquids and 10.8% for gas) for equity-accounted
entities compared with 2016. For more information on production see
Oil and gas disclosures for the group on page 259.
In aggregate, underlying production increased versus 2016.
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.
Book 1.indb 31
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BP Annual Report and Form 20-F 2017
31
Downstream
The execution of our strategy is delivering results and
building a business that is fit for now and the future. In
2017, we had our best year ever, with a replacement cost
profit of $7.2 billion.
Tufan Erginbilgic, chief executive, Downstream
In summary
>10%
fuels marketing earnings
growth versus prior year
1,100
convenience
partnership sites
44%
of lubricant sales
were premium grade
(2016 >20%)
(2016 880)
(2016 43%)
95.3% 1.7
15.3
refining availability
million barrels of oil
refined per day
million tonnes of
petrochemicals produced
(2016 95.3%)
(2016 1.7mmb/d)
(2016 14.2mmte)
Downstream profitability ($ billion)
2017
2016
2015
2014
2013
5.2
5.6
7.2
7.0
7.1
7.5
3.7
4.4
2.9
3.6
Replacement cost (RC) profit before interest and tax
Underlying RC profit before interest and tax
Business model
The Downstream segment has global marketing and manufacturing operations. It is the product and service-led arm of BP, made up of three
businesses:
Fuels
Lubricants
Petrochemicals
Includes refineries, logistic networks and
fuels marketing businesses, which together
with global oil supply and trading activities,
make up our integrated fuels value chains
(FVCs). We sell refined petroleum products
including gasoline, diesel and aviation fuel,
and have a significant presence in the
convenience retail sector.
Manufactures and markets lubricants
and related products and services to the
automotive, industrial, marine and energy
markets globally. We add value through
brand, technology and relationships, such
as collaboration with original equipment
manufacturing partners.
Manufactures and markets products
that are produced using industry-leading
proprietary BP technology, and are then
used by others to make essential consumer
products such as food packaging, textiles
and building materials. We also license our
technologies to third parties.
Strategy
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 is to deliver underlying performance improvement in order to expand earnings and cash
flow potential and improve our resilience to a range of market conditions. We also aim to further build competitively advantaged businesses. The
execution of our strategy in 2017 has continued to deliver, with growth in underlying earnings and cash flow at attractive returns.
Safe and reliable operations
This remains our core value and first priority
and we continue to drive improvement in
personal and process safety performance.
Profitable marketing growth
We invest in higher-returning fuels marketing
and lubricants businesses with growth
potential and reliable cash flows.
Advantaged manufacturing
We aim to have a competitively advantaged
refining and petrochemicals portfolio
underpinned by operational excellence and
to grow earnings potential, making the
businesses more resilient to margin volatility.
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 developing new products, offers
and business models that support the
transition to a lower carbon and digitally
enabled future over the longer term.
32
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BP Annual Report and Form 20-F 2017
Book 1.indb 32
03/04/2018 16:41:36
Market-led
growth
Growing retail
business
Every second of every day vehicles are
filling up with BP fuel across 18,300 sites –
making retail big business for BP.
Our premium fuel volumes grew by 6% in 2017 and
generated margins that are higher than our standard
grades. With a retail network that spans 19 countries, we
have one of the top three positions in terms of market
share in most of the markets where we operate.
But we’re not stopping there. We also have a significant
and growing retail convenience partnership offer which we
plan to continue to expand across our markets. This builds
on the success we have had with other industry leading
food retailers – like M&S Simply Food® and REWE to go®.
Our loyalty schemes, such as PAYBACK® and Nectar®,
are helping to strengthen customer relationships in key
markets – with loyalty card customers tending to shop
more frequently and spend more per visit.
We are also expanding our global portfolio into major
growth markets such as Mexico, China and Indonesia.
For the first time in 75 years, companies outside
Mexico can invest in its fuels market. We were the
first global brand to open retail sites there in early
2017 and by the end of the year we had more than
120 BP-branded sites, serving thousands of customers
a day. Mexico is one of the world’s largest consumer
gasoline and diesel markets globally and we plan to have
around 1,500 sites by 2021.
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Each day more
than 250,000
consumers
in Mexico are
choosing BP’s
differentiated
offer.
1,100
convenience
partnership sites
globally
Some examples of our
partnerships.
is now
available in
15 countries
Digital and advanced mobility
We are rolling out new digital and advanced
mobility customer offers. This includes our new
BPme app, which helps customers find a
convenient BP site, order coffee and pay for fuel
from their vehicle, and our investment in FreeWire,
a manufacturer of mobile electric vehicle rapid
charging systems, which we plan to roll out to
selected European retail sites in 2018.
BP Annual Report and Form 20-F 2017
33
Financial performance
Sale of crude oil through spot
and term contracts
Marketing, spot and term sales
2017
2016
$ million
2015
47,702
31,569
38,386
of refined products
159,475
126,419
148,925
Other sales and operating
revenues
Sales and other operating
revenuesa
RC profit before interest and taxb
Fuels
Lubricants
Petrochemicals
Net (favourable) adverse
impact of non-operating items
and fair value accounting effects
Fuels
Lubricants
Petrochemicals
Underlying RC profit before
interest and taxb
Fuels
Lubricants
Petrochemicals
Organic capital expenditure c
12,676
9,695
13,258
219,853
167,683
200,569
4,679
1,457
1,085
7,221
193
22
(469)
(254)
4,872
1,479
616
6,967
2,399
3,337
1,439
386
5,162
390
84
(2)
472
3,727
1,523
384
5,634
2,102
5,858
1,241
12
7,111
137
143
154
434
5,995
1,384
166
7,545
N/A
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.
c A reconciliation to GAAP information at the group level is provided on page 249. Organic
capital expenditure on a cash basis in 2015 is not available.
Financial results
Sales and other operating revenues in 2017 were higher due to higher
crude and product prices as well as higher sales volumes. Sales and
other operating revenues in 2016 were lower than 2015 due to lower
crude and product prices.
Replacement cost (RC) profit before interest and tax for the year ended
31 December 2017 included a net non-operating gain of $389 million,
primarily reflecting the gain on disposal of our share in the SECCO joint
venture in petrochemicals. The 2016 result 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, while the 2015 result included a net non-operating charge
of $590 million, mainly relating to restructuring charges. In addition, fair
value accounting effects had an adverse impact of $135 million,
compared with an adverse impact of $448 million in 2016 and a
favourable impact of $156 million in 2015.
After adjusting for non-operating items and fair value accounting effects,
underlying RC profit before interest and tax in 2017 was $6,967 million.
Outlook for 2018
We anticipate higher discounts for North American heavy crude oil
differentials but lower industry refining margins. We also expect the
level of turnaround activity to be similar in total, although higher in our
petrochemicals business.
Our fuels business
Our fuels strategy focuses primarily on fuels value chains (FVCs). This
includes building an advantaged refining portfolio through operating
reliability and efficiency, location advantage and feedstock flexibility, as
well as commercial optimization opportunities. 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.
Our fuels marketing business comprises retail, business-to-business
and aviation fuels. It is a material part of Downstream with a good track
record of growth. We have an advantaged portfolio of assets with good
growth potential, attractive returns and reliable cash flows. We continue
to grow our fuels marketing business through our differentiated
marketing offers and strategic convenience partnerships. We also
partner with leading retailers, creating distinctive retail offers that aim
to deliver good returns and reliable profit growth and cash generation.
Underlying RC profit before interest and tax for our fuels business was
higher compared with 2016, reflecting stronger refining performance
and growth in fuels marketing, partially offset by a weaker contribution
from supply and trading. Compared with 2015, the 2016 result was
lower, reflecting a significantly weaker refining environment and the
impact from a particularly large turnaround at our Whiting refinery. This
was 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.
Refining marker margin
We track the refining margin environment using 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)
2017
2016
$ per barrel
2015
18.8
16.9
11.7
10.4
12.9
14.1
16.9
13.2
10.0
9.0
10.9
11.8
24.0
19.0
14.5
12.7
15.4
17.0
32
24
16
8
2017
2016
2015
Five-year range
Jan
Feb Mar
Apr May
Jun
Jul
Aug
Sep
Oct
Nov
Dec
34
See Glossary
BP Annual Report and Form 20-F 2017
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The average global RMM in 2017 was $14.1/bbl, $2.3/bbl higher than in
2016. The increase was driven by tighter global supply demand balances
as well as lower product inventories compared with 2016.
Refining
At 31 December 2017 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 258.
Refinery throughputsa
US
Europe
Rest of worldb
Total
Refining availability
2017
713
773
216
1,702
95.3
2016
646
803
236
1,685
2015
thousand barrels per day
657
794
254
1,705
%
94.7
95.3
Underlying growth in our refining business is underpinned by our
multi-year business improvement plans, which comprise globally
consistent programmes focused on operating reliability and efficiency,
advantaged feedstocks and commercial optimization. Operating
reliability is a core foundation of our refining business and in 2017
operations remained strong, with refining availability sustained at
around 95.3%, refinery utilization rates at 90% (2016 91%) and overall
throughputs in 2017 higher compared with 2016. Our refinery portfolio –
along with our supply capability – enables us to process advantaged
crudes. For example, in the US, our three refineries all have location-
advantaged access to Canadian crudes which are typically cheaper than
other crudes. In 2017 we processed record levels of advantaged crude
across our portfolio. Our commercial optimization programme aims to
maximize value from our refineries by capturing opportunities in every
step of the value chain, from crude selection through to yield
optimization and utilization improvements.
Refining performance was stronger in 2017 compared with 2016,
reflecting continued strong operational performance, capturing higher
industry refining margins, efficiency benefits as well as increased
commercial optimization including the benefits of higher levels of
advantaged feedstock. This was, however, partially offset by a higher
level of planned turnaround activity. This stronger performance in 2017
resulted in an underlying improvement of more than 15% in our net cash
margin per barrel. Compared with 2015, refining performance in 2016
was lower, reflecting a significantly weaker refining environment and the
impact of a particularly large turnaround at the Whiting refinery. This was
partially offset by higher refining margin capture in our operations and
lower costs from our simplification and efficiency programmes.
a Refinery throughputs reflect crude oil and other feedstock volumes.
b Bulwer refinery in Australia ceased refining operations in 2015.
Fuels marketing and logistics
Across our fuels marketing businesses, 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. Through
our retail business, we supply fuel and convenience 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 in the transport and industrial sectors.
Retail is the most material part of our fuels marketing business and
a significant source of earnings growth through our strong market
positions, brands and distinctive customer offers. This is underpinned
by the strength of our retail convenience partnerships, technology such
as our most advanced premium fuels and our use of digital technology,
as well as our customer relationships. This differentiation enables our
growth in existing markets and supports our plans to expand our
footprint in new material markets such as Mexico, India, Indonesia and
China. In Mexico we became the first international oil company to open
a branded network since deregulation of the fuel market, and we
announced new retail joint ventures in Indonesia and, most recently,
China in February 2018.
We have a clear strategic frame to develop new customer offers in
mobility and to transition our business to a lower carbon future over
the longer term, building on our capabilities, retail assets and brand
strengths. We are actively developing new offers and business models
centred around digital and advanced mobility trends, for example we
have invested in FreeWire Technologies Inc., a manufacturer of mobile
electric vehicle rapid charging systems, and we have plans to roll out
FreeWire’s Mobi Charger units at selected BP retail sites in Europe in
2018, see Innovation in BP on page 46. Our acquisition of Clean Energy
Fuel Corporation’s biomethane production assets in 2017 means we are
now the largest supplier of renewable natural gas to the US transport
sector.
In 2017, we also completed the initial public offering of common units
in BP Midstream Partners LP, our subsidiary , which has interests in
certain crude oil, natural gas and refined product pipelines in the US.
Above: Engineers at our Cherry Point refinery in the US.
BP Annual Report and Form 20-F 2017
See Glossary
35
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Aviation
Our Air BP business is one of the world’s largest aviation fuels suppliers,
selling fuel to major commercial airlines as well as the general aviation
sector in over 800 locations across more than 50 countries globally. We
also provide aviation fuel consultancy services to airlines and airports
including the design, build and operation of aviation fuelling facilities.
Our Air BP business is differentiated through its strong market positions,
brand strength, partnerships, technology and customer relationships.
Our strategy aims to maintain a strong presence in our core locations in
Australia, New Zealand, Europe and the US, while expanding into major
growth markets that offer long-term competitive advantages, such as in
Asia and Latin America. We have marketing sales of more than 420,000
barrels per day, and in 2017 began marketing in Mexico, one of the
world’s fastest-growing aviation markets.
We are developing new offers and solutions in response to the needs of
our customers. In 2017 we entered into a strategic partnership and
preferred fuel supplier agreement with Victor, one of the world’s leading
on-demand marketplaces for private jet charters. We also recognize the
lower carbon commitments of the airline industry and continue to
develop our capability to meet the industry’s needs. In 2017 we began
supply of jet biofuel at two further locations in Sweden and Norway, in
addition to Norway’s Oslo airport where in 2016, we became the
world’s first supplier for commercial jet biofuel using existing fuelling
infrastructure.
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 27 and the range of contracts used is described in
Glossary – commodity trading contracts on page 289.
Above: Over-wing fuelling at Adelaide airport in Australia.
Fuels marketing performance in 2017 was higher compared with 2016,
reflecting continued earnings growth supported by higher premium fuel
volumes, which grew by 6%, and the continued rollout of our
convenience partnership model to over 220 more sites, bringing the total
number of convenience partnership sites to 1,100 across our retail
network. Compared with 2015, fuels marketing performance in 2016
was higher, reflecting retail growth.
Sales volumes
Marketing salesa
Trading/supply salesb
Total refined product sales
Crude oilc
Total
2017
2,799
3,149
5,948
2,616
8,564
thousand barrels per day
2015
2,835
2,770
5,605
2,098
7,703
2016
2,825
2,775
5,600
2,169
7,769
a Marketing sales include branded and unbranded sales of refined fuel products and lubricants
to both business-to-business and business-to-consumer customers, including service station
dealers, jobbers, airlines, small and large resellers such as hypermarkets as well as the
military.
b Trading/supply sales are fuel sales to large unbranded resellers and other oil companies.
c 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. 2017 includes
103 thousand barrels per day relating to revenues reported by the Upstream segment.
Retail sitesd
US
Europe
Rest of world
Total
Number of BP-branded retail sites
2015
7,000
8,100
2,900
18,000
2016
7,100
8,100
2,800
18,000
2017
7,200
8,100
3,000
18,300
d 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 include our interest in equity-accounted entities.
36
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BP Annual Report and Form 20-F 2017
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which include operational efficiency, deploying our industry-leading
proprietary technology, commercial optimization and competitive
feedstock sourcing. We also aim to grow our third-party technology
licensing income to create additional value.
In line with our strategy to focus our portfolio on areas where we have
industry-leading proprietary technologies and competitive advantage,
in 2017 we divested our 50% shareholding in the Shanghai SECCO
Petrochemical Company Limited joint venture in China for a
consideration of $1.7 billion.
In 2017 the petrochemicals business delivered a higher underlying RC
profit before interest and tax compared with 2016 – which in turn was
higher than 2015. The 2017 result reflected an improved margin
environment, stronger margin optimization, the benefits from our
efficiency programmes and a lower level of turnaround activity. This
was partially offset by the impact of the divestment of our interest in the
SECCO joint venture, which completed in the fourth quarter of 2017
and was classified as held for sale in the group balance sheet at 30
September. In 2017 we reduced our cash breakeven by more than 40%
compared with 2014, making our business more resilient to volatility in
the environment. Compared with 2015, the higher result in 2016
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.
Our petrochemicals production of 15.3 million tonnes in 2017 was higher
than 2016 and 2015 (2016 14.2mmte, 2015 14.8mmte). Production
was higher in 2017, reflecting record levels of production at a number
of our plants, a lower level of turnaround activity and the increase in our
interest in the Gelsenkirchen and Mülheim sites following the dissolution
of our German refining joint operation with Rosneft in 2016. These
increases were partially offset by the divestments of our share in the
SECCO joint venture in 2017 and the Decatur petrochemicals complex
in 2016.
In 2017 we completed the upgrade of our PTA plant at Cooper River in
South Carolina, US, to our industry-leading proprietary technology. This
technology is also used at our key PTA sites at Zhuhai in China and Geel
in Belgium. Since its deployment, new production records have been set
at Zhuhai and Geel.
We have also leveraged this technology to develop a lower carbon PTA
solution for manufacturers, brand owners and their customers. Our
PTAir brand, which was first launched in Europe in 2016, is now available
globally. The introduction of PTAir in China in 2017 has demonstrated our
long-term commitment to both promoting improved sustainability in the
polyester industry and helping China to move towards a lower carbon
future.
Our lubricants business
We manufacture and market 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. 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.
Above: Castrol EDGE engine oil.
Our strategy is to focus on our premium lubricants and growth
markets while leveraging our strong brands, technology and customer
relationships – all of which are sources of differentiation for our business.
With more than 60% of profit generated from growth markets and more
than 44% of our sales from premium grade lubricants, we have an
excellent base for further expansion and sustained profit growth.
We have a robust pipeline of technology development through which
we seek to respond to engine developments and evolving consumer
needs and preferences, including lower carbon options. We apply
our expertise to create differentiated, premium lubricants and
high-performance fluids for customers in on-road, off-road, sea and
industrial applications. In 2017 in the US, we launched Castrol EDGE
BIO-SYNTHETIC, an engine oil that uses 25% plant-derived oil
compounds while delivering a high level of performance.
The lubricants business delivered an underlying RC profit before interest
and tax that was similar compared with 2016 – which in turn was higher
compared with 2015. The 2017 results reflected growth in premium
brands and growth markets, offset by the adverse lag impact of
increasing base oil prices. The 2016 results also reflected continued
strong performance in growth markets and premium brands as well as
lower costs achieved through simplification and efficiency programmes.
Our petrochemicals business
Our petrochemicals business manufactures and markets three main
product lines: purified terephthalic acid (PTA), paraxylene (PX) and acetic
acid. These have a large range of uses including polyester fibre, food
packaging and building materials. We also produce a number of other
specialty petrochemicals products. In addition, we manufacture olefins
and derivatives at Gelsenkirchen and solvents at Mülheim in Germany,
the income from which is reported in our fuels business.
Along with 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.
Our strategy is to grow our underlying earnings and ensure the business
is resilient to margin volatility, positioning ourselves to capture growth
and investment opportunities in an attractive and growing market. We
do this through the execution of our business improvement programmes
Book 1.indb 37
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BP Annual Report and Form 20-F 2017
See Glossary
37
Rosneft
Rosneft is the largest oil company
in Russia, with a strong portfolio
of current and future opportunities.
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 our participation in the Rosneft
Board of Directors, collaboration on safety, 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.
2017 summary
• Rosneft continued optimizing its portfolio and increased total
hydrocarbon production by 6.5%.
• BP received $190 million, net of withholding taxes, in July (2016
$332 million, 2015 $271 million), representing its share of Rosneft’s
dividend of 5.98 Russian roubles per share. This dividend was
35% of Rosneft’s 2016 IFRS net profit.
• Rosneft implemented a new dividend policy in September, which
provides for a target level of dividends of no less than 50% of IFRS
net profit, and a target frequency of dividend payments of at least
twice a year.
• BP received $124 million, net of withholding taxes, in October,
representing its share of Rosneft’s interim dividend of 3.83 Russian
roubles per share. This dividend was 50% of Rosneft’s IFRS net
profit for the first half of 2017.
• Rosneft completed the acquisition of a 100% interest in the Kondaneft
project in April, which is developing four licence areas in the Khanty-
Mansiysk Autonomous District in West Siberia. The acquisition price
was approximately $700 million.
• Rosneft completed the transaction for the sale of a 20% interest in its
Verkhnechonskneftegaz subsidiary to the Beijing Gas Group in June,
for around $1.1 billion.
• Rosneft completed the transaction to acquire a 49.13% stake in Essar
Oil Limited (EOL), an Indian downstream business, from Essar Energy
Holdings Limited and its affiliates (the Essar group) in August. As a
result of this transaction, Rosneft acquired 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 acquisition price totalled $3.9 billion.
• Rosneft completed the acquisition of a 30% stake in a concession
agreement to develop the Zohr field in Egypt from the Italian company
Eni S.p.A. (Eni) for $1.1 billion in October. Rosneft is also refunding its
share in past project costs to Eni, which is estimated at $1.1 billion. Eni
retains a 60% stake and BP holds the remaining 10%.
• Two BP nominees, Bob Dudley and Guillermo Quintero, serve on
Rosneft’s Board. The number of directors on the Board increased
from nine to 11 in September. Bob Dudley became chairman of its
Strategic Planning Committee, and Guillermo Quintero
is a member of its HR and Remuneration Committee.
• US and EU sanctions imposed in 2014 remain in place on certain
Russian activities, individuals and entities, including Rosneft.
In 2017 the US imposed additional sanctions on certain Russian
and international activities and entities, including 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 5.7mmboe/d
in 2017. Gas production for the year increased by 2% compared with
2016 to 68.4bcma or 6.62bcf/d.
38
See Glossary
BP Annual Report and Form 20-F 2017 • BP holds a 20% interest in Taas-Yuryakh Neftegazodobycha (Taas),
a joint venture with Rosneft and a consortium comprising Oil India
Limited, Indian Oil Corporation Limited and Bharat PetroResources
Limited. Taas is developing the Srednebotuobinskoye oil and gas
condensate field. BP‘s interest in Taas is reported through the
Upstream segment.
• Rosneft (51%) and BP (49%) jointly own Yermak Neftegaz LLC
(Yermak). This joint venture conducts onshore exploration in the West
Siberian and Yenisei-Khatanga basins and currently holds seven
exploration and production licences. The venture is also carrying out
further appraisal work on the Baikalovskoye field, an existing Rosneft
discovery in the Yenisei-Khatanga area of mutual interest. BP’s
interest in Yermak is reported through the Upstream segment.
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• Rosneft, BP and Western GeCo (a subsidiary of Schlumberger)
continued their 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.
• Rosneft and BP signed an agreement on strategic co-operation in
gas and a memorandum of understanding in respect to the sale and
purchase of natural gas in Europe in June. We agreed to develop
integrated co-operation in gas and aim to jointly implement gas
projects focused on gas exploration and production, LNG
production, supply and marketing in Russia and abroad.
• In June Rosneft and BP also signed an agreement for collaboration
in labour protection, and industrial and fire safety, including in the
implementation of joint oil and gas projects.
• Rosneft is the leading Russian refining company based on throughput.
It owns and operates 13 refineries in Russia. Rosneft also owns and
operates more than 2,960 retail service stations in Russia and abroad.
These include Rosneft-branded sites, as well as BP-branded sites
operating under a licensing agreement. Downstream operations
include jet fuel, bunkering, bitumen and lubricants. Rosneft refinery
throughput in 2017 reached a record level of 2,288mb/d versus
2,028mb/d in 2016.
• Rosneft’s largest shareholder is Rosneftegaz JSC (Rosneftegaz),
which is wholly owned by the Russian government. Rosneftegaz's
shareholding in Rosneft is 50% plus one share.
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 two of 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.
• Technical services – collaborate on the provision of technical and
HSE services on a contractual basis to improve asset performance.
The following developments and activities in 2017 have served to
support and progress this strategy:
• In December Rosneft and BP announced an agreement to form a joint
venture to develop subsoil resources within the Kharampurskoe and
Festivalnoye licence areas in Yamalo-Nenets Autonomous Okrug in
northern Russia. Rosneft will hold a majority stake of 51% and BP will
hold a 49% stake. Completion of the deal, subject to external
approvals, is expected in 2018.
Book 1.indb 39
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BP Annual Report and Form 20-F 2017
See Glossary
39
Balance sheet
Investments in associates c
(as at 31 December)
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 liquidsf
Natural gas (billion cubic feet)g
Total hydrocarbons (mmboe)
2017
2016
$ million
2015
10,059
8,243
5,797
2017
2016
2015
900
4
904
1,308
1,129
836
4
840
1,279
1,060
809
4
813
1,195
1,019
5,402
131
5,533
4,823
5,330
47
65
4,871
5,395
13,522 11,900 11,169
6,796
7,447
7,864
c See Financial statements – Note 15 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 338 million barrels of crude oil (347 million barrels at 31 December 2016) in respect
of the 6.31% non-controlling interest (6.58% at 31 December 2016) in Rosneft, held assets
in Russia including 32 million barrels (28 million barrels at 31 December 2016) held through
BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha.
g Includes 306 billion cubic feet of natural gas (300 billion cubic feet at 31 December 2016) in
respect of the 2.30% non-controlling interest (2.53% at 31 December 2016) in Rosneft held
assets in Russia including 12 billion cubic feet (3 billion cubic feet at 31 December 2016)
held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha.
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 15 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)
2017
923
(87)
836
–
836
2016
643
(53)
590
(23)
567
52.84
41.68
$ million
2015
1,314
(4)
1,310
–
1,310
$ per barrel
50.97
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 $(2) million (2016 $3 million, 2015 $16 million) of foreign exchange (gain)/losses
arising on the dividend received.
Market price
The price of Urals delivered in North West Europe (Rotterdam) averaged
$52.84/bbl in 2017, $1.35/bbl below dated Brent . The differential to
Brent narrowed from $2.06/bbl in 2016 as OPEC production cuts
tightened the market for medium sour crude.
Financial results
Replacement cost (RC) profit before interest and tax for the segment
for 2016 included a non-operating gain of $23 million, whereas the 2017
and 2015 results did not include any non-operating items.
After adjusting for non-operating items, the increase in the underlying
RC profit before interest and tax compared with 2016 primarily reflected
higher oil prices. The result also benefited from a $163-million gain
representing the BP share of a voluntary out-of-court settlement
between Sistema, Sistema-Invest and the Rosneft subsidiary,
Bashneft. These positive effects were partially offset by adverse
foreign exchange effects. Compared with 2015, the 2016 result was
primarily affected by lower oil prices and increased government take,
partially offset by favourable duty lag effects. See also Financial
statements – Notes 15 and 30 for other foreign exchange effects.
40
See Glossary
BP Annual Report and Form 20-F 2017
Book 1.indb 40
03/04/2018 16:42:08
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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Financial performance
Sales and other operating revenuesa
RC profit (loss) before interest and tax
Gulf of Mexico oil spill
Other
RC profit (loss) before interest and tax
Net adverse 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 b
2017
1,469
2016
1,667
(2,687)
(1,758)
(4,445)
2,687
160
2,847
(1,598)
339
(6,640)
(1,517)
(8,157)
6,640
279
6,919
(1,238)
229
$ million
2015
2,048
(11,709)
(1,768)
(13,477)
11,709
547
12,256
(1,221)
N/A
a Includes sales to other segments.
b A reconciliation to GAAP information at the group level is provided on page 249. Organic capital expenditure on a cash basis in 2015 is not available.
The replacement cost (RC) loss before interest and tax
for the year ended 31 December 2017 was $4,445
million (2016 $8,157 million, 2015 $13,477 million). The
2017 result included a net charge for non-operating items
of $2,847 million, primarily relating to costs for the Gulf of
Mexico oil spill (2016 $6,919 million, 2015 $12,256
million). For further information, see 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 2017 was $1,598 million, higher
than 2016 due to weaker business results, higher
corporate costs and adverse foreign exchange effects
which had a favourable effect in 2016. The underlying RC
loss before interest and tax in 2016 was $1,238 million,
similar to the loss of $1,221 million in 2015.
Outlook
Other businesses and corporate annual charges,
excluding non-operating items, are expected
to be around $1.4 billion in 2018.
Gulf of Mexico oil spill
Gulf of Mexico oil spill
Further significant progress was made in 2017
Further significant progress was made in 2017
toward resolving outstanding matters related
toward resolving outstanding matters related
to the 2010 Gulf of Mexico oil spill. The court
to the 2010 Gulf of Mexico oil spill. The court
supervised settlement programme’s
supervised settlement programme’s
determination of business economic claims was
determination of business economic claims was
substantially completed, although a significant
substantially completed, although a significant
number of individual claims determined have been
number of individual claims determined have been
and continue to be appealed by BP and/or the
and continue to be apppeap led byy BP and/or the
claimants. Determinations with respect to
claimants. Determinations with respect to
remaining business economic loss claims are
remainingg business economic loss claims are
expected to be issued in the first half of 2018.
expected to be issued in the first half of 2018.
The process safety monitor’s term of appointment
The process safety monitor’s term of appointment
came to an end in January 2018. The ethics
came to an end in January 2018. The ethics
monitor’s term of appointment will come to an
monitor’s term of appointment will come to an
endend inin 20201919 andand wewe cocontintinuenue toto woworkrk witwith hh himim
end in 2019 and we continue to work with him
to review ongoig ng g prop greg ss.
to review ongoing progress.
A further $2.7 billion pre-tax charge was recorded
A further $2.7 billion pre-tax charge was recorded
in 2017 and the cumulative pre-tax income
in 2017 and the cumulative pre-tax income
statement charge since the incident in April 2010
statement charge since the incident in April 2010
amounted to $65.8 billion as at 31 December 2017
amounted to $65.8 billion as at 31 December 2017
For further information, see Financial statements
For further information, see Financial statements
– Note 2.
– Note 2.
Book 1.indb 41
03/04/2018 16:42:12
BP Annual Report and Form 20-F 2017
See Glossary
41
Alternative Energy
Left: Lightsource BP's floating
solar farm on the Queen
Elizabeth II reservoir, just
outside London.
We have been investing in renewables
for many years – and our focus today
is on biofuels, biopower, wind energy
and solar energy.
Renewables are the fastest growing form of energy.
They account for around 4% of energy demand today
(excluding large-scale hydroelectricity). By 2040 that
could grow to at least 14% – an exceptional rate of
growth for the energy industry.
As part of our approach to building our alternative energy
business, we are looking to grow our existing businesses
and to develop further new businesses and partnerships
to deliver sustainable value.
Biofuels
We believe that biofuels offer one of the best large-scale
solutions to reduce emissions from transportation.
We produce ethanol from sugar cane in Brazil. This ethanol
has life cycle greenhouse gas emissions that are 70%
lower than conventional transport fuels. In 2017 our three
sites produced 776 million litres of ethanol equivalent.
Brazil is one of the largest markets globally for ethanol
fuel. To better connect our ethanol production with the
country’s main fuels markets, we are partnering with
Copersucar, the world’s leading ethanol and sugar trader,
to operate a major ethanol storage terminal.
Our largest biofuels mill is certified to Bonsucro, an
independent standard for sustainable sugar cane
production.
Our strategy is enabled by:
• Safe and reliable operations – continuing to drive
improvements in personal, process and transport
safety.
• Competitive feedstock – concentrating our efforts
in Brazil, which has one of the most cost-competitive
biofuel sources currently available in the world.
• Domestic and international markets – selling
bioethanol and sugar domestically in Brazil and also
to international markets such as the US and Europe
through our integrated supply and trading function.
Advanced biofuels
Butamax®, our 50/50 joint venture with DuPont, has
developed technology that converts sugars from corn
into an energy-rich biofuel known as bio-isobutanol. It can
be blended with gasoline at higher concentrations than
ethanol and transported through existing fuel pipelines
and infrastructure. Butamax® plans to upgrade its recently
acquired ethanol plant in Kansas to enable it to produce
bio-isobutanol to demonstrate the technology to ethanol
producers.
Biopower
We create biopower by burning bagasse, the fibre that
remains after crushing sugar cane stalks. In 2017 our
three biofuels manufacturing facilities produced around
850GWh of electricity – enough renewable energy
to power all of these sites and export the remaining 70%
to the local electricity grid.
This is a low carbon power source, with the CO2 emitted
from burning bagasse offset by the CO2 absorbed by
sugar cane during its growth.
Wind energy
We have interests in 14 sites in the US with a net
generating capacity of 1,432MW, making BP one of
the top wind energy producers in the country. We
continue to optimize our business by seeking out
technological advancements and finding ways to deliver
power more efficiently.
Solar energy
BP has partnered with Lightsource, Europe’s largest solar
development company, which focuses on the acquisition,
development and long-term management of large-
scale solar projects. We are bringing our global scale,
relationships and trading capabilities to help accelerate
Lightsource’s expansion worldwide. The company
has been rebranded as Lightsource BP. We are investing
$200 million in Lightsource BP over three years and will
hold a 43% stake in the company with two seats on its
board.
42
BP Annual Report and Form 20-F 2017
Book 1.indb 42
03/04/2018 16:42:18
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Right: Looking out to sea from
our BP-operated British Renown
oil tanker in the US.
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 2017 BP
had four vessels supporting operations in Alaska and
49 BP-operated and 22 time-chartered vessels for our
international oil and gas shipping operations. In 2017
13 new oil tankers were delivered into the BP-operated
fleet. There are no new oil tankers planned for delivery
in 2018. However, we have six technically advanced
LNG tankers on order and planned for delivery into the
BP-operated fleet between 2018 and 2019.
The LNG tankers are currently under construction in
Daewoo Shipbuilding and Marine Engineering in South
Korea. The first ship was launched in September and
will be delivered in the first half of 2018. When
delivered they will be the largest and most fuel
efficient LNG ships BP has ever built. Their advanced
gas burning diesel engines allow a step change in
flexibility and efficiency. The ships also have the
facilities to re-liquefy gas and use it for cargo
conditioning – making them extremely commercially
flexible. 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 holds foreign exchange and
interest rate products in the financial markets to hedge
group exposures. In addition, treasury generates
incremental value through optimizing and managing cash
flows and the short-term investment of operational cash
balances. For further information, see Financial
statements – Note 27.
Insurance
The group generally restricts its purchase of insurance to
situations where this is required for legal or contractual
reasons. 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.
Book 1.indb 43
03/04/2018 16:42:27
BP Annual Report and Form 20-F 2017
43
Innovation in BP
3,600
patents and applications
8
major technology centres
Technology is ever-present
in all that we do – from safely
discovering and recovering oil
and gas, to renewable energy,
digital, and lower carbon
fuels and products.
We seek innovations that help to make
our operations and products more
efficient and sustainable.
And by partnering with early and
growth stage start-ups, we invest in
emerging technologies that are scalable
and commercially viable. We also
complement our comprehensive research
capability with external collaborations that
provide a range of specialisms, supported
by innovative academic programmes.
We have scientists and technologists at
eight major technology centres in the US,
UK, Asia and Germany. In 2017 we invested
$391 million in research and development
(2016 $400 million, 2015 $418 million). This
excludes the investment in technology
made through venturing – which gives us
alternative access to innovation.
BP and its subsidiaries hold more than
3,600 granted patents and pending patent
applications throughout the world.
bp.com/technology
More information
Technology Outlook
How technology could influence
the way we meet the energy
challenge into the future.
bp.com/technologyoutlook
Technology across the business
The right technology is central to the safety
and reliability of our operations. In Upstream,
we seek to increase recovery and gain new
access. And in Downstream we develop and
apply technology that enhances operational
integrity, boosts conversion efficiency,
reduces CO2 emissions or helps to provide
high-performance products for our customers.
Between
8-15%
fuel savings
Helping heavy-duty vehicles reduce carbon emissions
While the focus of reducing emissions
has been on battery power for passenger
and small vehicle fleets, the solution
for heavy-duty vehicles such as lorries
isn’t as obvious. To help tackle this, we are
developing a number of technologies
that offer a range of ways for heavy-duty
vehicles to reduce emissions.
Our acquisition of the renewable natural
gas business of Clean Energy Fuel Corp. is
helping to make renewable energy more
accessible for natural gas powered vehicle
fleets, including trucks. Biogas is produced
entirely from organic waste and is estimated
to result in up to 70% lower greenhouse
gas emissions than from equivalent gasoline
or diesel-fuelled vehicles.
We are working to improve the safety and
efficiency of trucks through our investment
in Peloton Technology. The business has
developed connected and automated vehicle
technology for commercial vehicles, using
the same approach as cyclists who race in
close formation to travel as fast as the leader
but with less effort. Linked pairs of trucks
have synchronized acceleration and braking
to maintain a safe distance between the
vehicles. Travelling in this way can reduce
emissions and result in estimated fuel
savings of between 8-15%.
44
BP Annual Report and Form 20-F 2017
Improving oil and gas recovery
Operational decision-making is being
transformed by a combination of cloud
technology and big data software solutions.
Our wells data platform Argus holds historical
and real-time data in our proprietary data lake
on nearly all of the 2,500 wells we operate
globally, making data available to any relevant
engineer, anytime. Well reviews that used
to take days of preparation can now be
done live using Argus, leaving more time
to explore new ways to deliver efficiencies
and improve production rates.
We recently deployed a new proprietary
seismic processing algorithm called Full
Waveform Inversion in our Gulf of Mexico
business, which lets us see through the salt
to the reservoirs below. Applied to BP’s four
hubs in the Gulf of Mexico, it has helped
us identify significant additional resources.
We ran that algorithm in just two weeks at
our centre for high performance computing
in Houston – in 1999 that would have
taken us more than 2,000 years using
available computer power.
Sand production caused from weak rock
breaking down under pressure creates a
challenge for our industry. If sand enters oil
production facilities, it can cause erosion
and disrupt production efficiency.
Creating low carbon businesses
New technologies can help pave the way
to a lower carbon future. We are building
low carbon into what we do, across the
business – in ways that can help generate
value over the long term.
We are an investor and an end-user
of the technologies we invest in.
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.
Our venturing partnerships help us
to understand and develop solutions
for the future.
We invest to help companies develop
technology quickly – often for our own use.
Our investments include:
• Advanced mobility
• Carbon management
• Low carbon power and storage
• Bio and low carbon products
• Digital energy.
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~2,500
wells with Argus
real-time data
0000010010000000100100100 00 00000 0111101101101011011010010110101010101101100111110111110110010101010111011110010101010100100100100101001001010010110101001010101010 01010111010111011010110101111101010010101000010010001010100100000 1110101010101110101010100100101111111000111110111111011111010
000101001000000 000010101010111011000000 0000000000000001110101111010111111101011110011100100101111001111010100001010001101101101 0000000000010101010101000000000000000000010100000000101000111100101100100000100000100000001010001010111 11111111100111111111101011111101011101011101101011101 010101010001000 00 1010110011 11 1
01010101
01000100011000000000 00000 0000 00000000011101010100010110111010110001100100110001110011101101001001010010010010000101000 1011011101101010010010000101001000 1000010111010111 0001011100010
00001011100000000 0010001100100011111010011001001100111111 110001010101010000111001 10110111011011010 01010111000011010110 100001011110 000011111101101
00101110001101000 00011010010010111111000001 00011100000000000000 1011010101 1111 11100001111111
01001110000000000001011100001110101000101110100111111011100011000111 11 0101001101000001000 0000 00000000000 101010110101011110111011111111000010110000010101010000101010100010100000100 0100 0100 000 00100 111100010111111111101111111111 1010 00000101011111100111111
000000010100101010100101000000000010000000010010011001000010001010 000000010100001010110001111000010011000000011110010110000100 00000 00 00000001000100010000010001110000 001100010110110110110101011101011011110001111010011011 10100101000100010000101011000010010101100001000 11111111
001000000111111000000000011000110011011001100001111000000000011000000 000 001 10110001111001111 1001001010010111
000001010010101111111000000000000000111111000000111100000000001110000000111000000011001100001100010001100010010101000100111001100110110010 00100010010001001001000 00 1111111
10
Through our venturing partnership with
BiSN, we help to protect oil production rates
by shutting off unwanted water and gas.
BiSN applies heat technology in a well to
melt alloys so they can flow into any spaces
within the cemented well. When cooled,
the alloys solidify and seal the well, inhibiting
water or gas entry. We have deployed
this novel BiSN technology successfully
in the Gulf of Mexico and Angola.
Working in partnership
Carbon capture, use and storage
technology (CCUS), where CO2 can be
captured and prevented from entering the
atmosphere, is another important means
of reducing emissions. BP is working with
the Oil and Gas Climate Initiative (OGCI) to
speed up wide-scale use of CCUS, which
is one of the main focus areas for OGCI’s
$1-billion investment vehicle. In 2017
we committed funding through OGCI to
advance designs for a full-scale gas power
plant with CCUS – one that can receive
government support and attract private
sector investors.
Using fibre optics cables inside our wells,
we ‘listen’ to the rock, so we can intervene
if issues arise. We have deployed this
technology in more than 30 wells to date
– with many more planned globally, and
are now investigating other applications
for the technology, including 4D seismic
and well integrity monitoring.
$400 million+
invested in corporate venturing since
2006 – $100 million in 2017 alone.
40+
active investments in our venturing
portfolio, with more than 200
co-investors and 12 technologies
used in BP.
Sustainable raw materials
We are helping commercialize production
of new high-performance wood. Tricoya
technology changes the physical properties
of wood chips that are used to make MDF
panels with enhanced durability and stability.
The panels can be used outside and in wet
areas – where concrete, plastic or metal
materials would usually be needed. The
lightweight and sustainable raw material offers
benefits to the construction, joinery and civil
engineering industries. BP and Tricoya have
formed a consortium to build a plant in the UK,
producing more durable wood chips.
Book 1.indb 45
03/04/2018 16:42:42
BP Annual Report and Form 20-F 2017
45
Turning carbon into concrete
Our investment in Solidia, a cement and
concrete company, is supporting a new
technology to produce cement in a way
that generates fewer emissions – using
CO2 instead of water to cure the concrete.
The technology has the potential to lower
emissions in concrete production by
up to 70%, and allows 80% of the
water used in its production process
to be recycled.
Rapid mobile charging
BP has invested $5 million in FreeWire,
a US manufacturer of mobile electric
vehicle rapid charging systems, and we
plan to roll out the charging facilities for
use at selected BP retail sites in Europe
during 2018. This investment will help
to build our understanding of this fast-
evolving market.
$20 million
invested in Beyond Limits
20+
years supporting NASA
Previously used in deep space
exploration – our venturing
partnership with Beyond Limits
is using artificial intelligence
(AI) technology to transform
the way we manage reservoirs
here on Earth.
Our investment in the start-up company
is helping develop and commercialize the
same technology that successfully
supported NASA’s space programme for
more than 20 years for the oil and gas
industry.
Beyond Limits aims to adapt and deliver
its AI software to tackle industrial and
business challenges on Earth. The
work uses machine learning and human
knowledge to simulate human reasoning,
with the same exploration techniques
that NASA’s Curiosity Rover used on the
surface of Mars.
We are supporting this work to help
accelerate its delivery and provide the
energy sector with new levels of process
automation and better insight and
effectiveness across all operations.
The work supports BP’s vision of using
digital technology to help transform our
organization. And we believe that it could
fundamentally change how we locate
and develop reservoirs, produce and
refine crude oil, market and supply refined
products and make unmanned repairs
possible for dangerous maintenance.
70%
potential
emissions
reduction
Venturing and
low carbon across
multiple fronts
Going beyond
the limits
Alternative
thinking
New
technologies
Disruptive
business
models
46
BP Annual Report and Form 20-F 2017
Sustainability
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 2017 sustainability focus
These sustainability issues are the ones that
could impact our business the most and that
are of greatest interest to our stakeholders:
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Safety and security
Climate change
Managing our
impacts
Value to society
Human rights
Environment
Ethical conduct
Our people
More information
BP Sustainability Report
Publishes April
Advancing the energy transition
Publishes April
Safety and security
Safety is a core value and our number
one priority. Our stated aim is to
have no accidents, no harm to people
and no damage to the 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 2017 BP reported one fatality – a firefighter who died
in the course of his duties for our biofuels business in
Brazil. Nothing matters more than every one of our
people returning home safely each day. We deeply regret
this loss and continue to work towards eliminating
injuries and fatalities in our work.
Preventing incidents
We carefully plan our operations, identifying potential
hazards and managing risks at every stage. We design
our facilities to appropriate standards and manage them
throughout their lifetime.
We track our safety performance using industry metrics
such as the American Petroleum Institute recommended
practice 754 and the International Association of Oil &
Gas Producers recommended practice 456.
Process safety events
(number of incidents)
150
100
50
2013
2014
2015
2016
2017
Tier 1
Tier 2
Recordable injury frequency
(workforce incidents per 200,000 hours worked)
0.8
0.6
0.4
0.2
Workforce
Employees
Contractors
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
2017
0.22
0.20
0.23
American Petroleum Institute US benchmarka
International Association of Oil & Gas Producers benchmarka
aAPI and OGP 2016 data reports are not available until May 2017.
Book 1.indb 47
03/04/2018 16:42:55
BP Annual Report and Form 20-F 2017
See Glossary
47
Tier 1 process safety events a
Tier 2 process safety eventsb
Oil spills – numberc
Oil spills contained
Oil spills reaching land and water
Oil spilled – volume (thousand litres)
Oil unrecovered (thousand litres)
2017
18
61
139
81
58
886
265
2016
16
84
149
91
58
677
311
2015
20
83
146
91
55
432
142
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, to check how they are
managing risks.
Operating management system
BP’s OMS is a group-wide framework designed to help us manage
risks in our operating activities and drive performance improvements.
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 by setting
a common framework that our operations must work to. Recently
acquired operations need to transition to OMS. See page 49 for
information about contractors and joint arrangements .
a Tier 1 process safety events 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.
b Tier 2 events are those of lesser consequence.
c Number of spills greater than or equal to one barrel (159 litres, 42 US gallons).
In 2017 we continued to see a reduction in the overall number of process
safety events, despite a slight increase in tier 1, the more serious events.
We investigate safety incidents and near misses, including low
probability, high consequence events. And we use leading indicators,
like inspections and equipment tests, to monitor the strength of controls
to prevent incidents. What we learn from performance insights helps us
focus our safety efforts. For example, we are introducing techniques for
teams to analyse and redesign tasks to reduce the chance of mistakes
occurring.
Proactively managing equipment corrosion is also a focus for us – and
we believe this is helping to deliver improvements in process safety in
our upstream and downstream businesses.
Keeping people safe
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.
We monitor and report on key workforce personal safety metrics and
include both employees and contractors in our data.
Recordable injury frequencyd
Day away from work case
frequencye
Severe vehicle accident ratef
2017
0.22
0.055
0.03
2016
0.21
0.051
0.05
2015
0.24
0.061
0.11
d Incidents that result in a fatality or injury per 200,000 hours worked.
e Incidents that result in an injury where a person is unable to work for a day (shift) or more
per 200,000 hours worked.
f The figures for 2016 and 2017 are based on our new definition which aligns with
industry practice.
We have seen a small increase in our recordable injury frequency and
day away from work case frequency compared to last year. Improving
safety in our operations is a high priority and we are working on it right
across the business.
48
See Glossary
BP Annual Report and Form 20-F 2017
Above: Monitoring global events at our 24-hour response information
centre in the UK.
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We use a range of measures to manage this risk, including the use
of cyber security policies and procedures, security protection tools,
ongoing detection and monitoring of threats, and testing of response
and recovery procedures. We collaborate closely with governments, law
enforcement and industry peers to understand and respond to new and
emerging threats. To encourage vigilance among our employees, our
cyber security programme covers topics such as email phishing and the
correct classification and handling of our information.
Working with contractors and partners
More than half of the hours worked by BP are carried out by contractors.
So their skills and performance are vital to our ability to carry out our
work safely and responsibly. Our standard model contracts include
health, safety and security requirements. Through bridging documents,
we define the way our safety management system co-exists with those
of our contractors to manage risk on a site. And for our contractors
facing the most serious risks, we conduct quality, technical, health,
safety and security audits before awarding contracts. Once they start
work, we continue to monitor their safety performance.
Our OMS includes requirements and practices for working with
contractors. We expect and encourage our contractors and their
employees to act in a way that is consistent with our code of conduct.
We take appropriate action if those expectations, or their contractual
obligations, are not met.
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 aspects of our
business where we are the operator – as we directly manage the
performance of these operations.
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 have a group framework to assess and manage BP’s
exposure related to safety, operational and bribery and corruption risk
from our participation in these types of arrangements.
We monitor performance and how risk is managed in our joint
arrangements, whether we are the operator or not.
Above: Operations at our Cherry Point refinery in the US.
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, our wells data platform Argus holds
historical and real-time data on nearly all of the 2,500 wells we operate
globally, giving our engineers the ability to access and analyse alerts
quickly and remotely. This enables early identification and rapid
response should an issue arise (see page 45).
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.
Security
As a global business, BP monitors for hostile actions that could harm our
people or disrupt our operations. We particularly look at operating areas
affected by political and social unrest, terrorism, armed conflict or
criminal activity. We also run exercises and drills to test our procedures
and help ensure our people are prepared in the event of an emergency.
We take steps to help people stay safe when they are travelling on
business. Our 24-hour response information centre keeps watch over
global events and related developments. This meant that in March 2017
we were aware of the terrorist attack in London’s Westminster almost
immediately. Within minutes we knew which employees had scheduled
meetings or travel plans in the surrounding area, so we were able to
confirm their safety and provide advice.
Oil spill preparedness
Our requirements for oil spill preparedness and response planning
incorporate updated external requirements and what we have learned
over many years. We are also using technologies to strengthen our
response to oil spills. Working with Oil Spill Response Limited, an
industry-funded co-operative, and others, we used satellites, drones and
autonomous underwater vehicles in an oil spill response exercise. This
enabled us to study an oil plume from a small controlled release and the
effectiveness of dispersant in helping it to biodegrade.
Cyber threats
Cyber attacks are on the rise and our industry is subject to evolving
risks from a variety of cyber threat actors, including nation states,
criminals, terrorists, hacktivists and insiders. We have experienced
threats to the security of our digital infrastructure, but none of these
had a significant effect on our business in 2017.
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BP Annual Report and Form 20-F 2017
49
Climate change
Our strategy sets us up to help advance the energy
transition, while meeting the needs for energy today.
To help drive the energy transition, we are working to reduce our
operational emissions, produce new efficient fuels and lubricants for
our customers and to build up our low carbon businesses.
Reducing emissions in our operations
We have set an emissions reduction target of 3.5 million tonnes
out to 2025. Our operating businesses aim to deliver this through
improved efficiency, less methane emissions and reduced flaring
– leading to permanent, quantifiable GHG reductions.
Improving our products
We are increasing gas in our portfolio, helping to meet the rising
demand for cleaner energy. We are continuing to innovate with
efficient fuels, lubricants and chemicals that can help our
customers and consumers lower their emissions – as well as
exploring opportunities to use our retail network to support the
electrification of transport.
Creating low carbon businesses
We are building up our renewable energy portfolio – focusing on
biofuels, biopower, wind and solar. And we have established a
dynamic venturing arm that is working on multiple fronts –
through joint ventures , creative collaborations and new business
models.
Working with others
We are collaborating with others to help address this global
challenge. As one example, the Oil and Gas Climate Initiative
(OGCI) – 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. In 2017, OGCI announced its intent to provide technical
and financial support for the world’s first global methane study.
Advancing Low Carbon programme
BP's new Advancing Low Carbon accreditation programme is designed
to motivate every part of BP to pursue lower carbon opportunities – by
highlighting BP activities that demonstrate a better carbon outcome. The
activities initially selected include emission reductions in our operations,
carbon neutral products and investments in low carbon technologies.
See bp.com/advancinglowcarbon for more information.
Calling for a price on carbon
BP believes that carbon pricing by governments provides the right
incentives for everyone – energy producers and consumers alike – to
play their part in reducing emissions. It makes energy efficiency more
attractive and makes lower carbon solutions, such as renewables and
CCUS, more cost competitive.
To help anticipate greater regulatory requirements affecting our GHG
emissions, we use a carbon cost when evaluating our plans 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.
Task Force on Climate-related
Financial Disclosures
The TCFD was established by the Financial Stability Board
with the aim of improving disclosure of climate-related
risks and opportunities. Our reporting provides information
relevant to each of the four TCFD recommendations.
Governance
Annual Report (page 70), Sustainability Report (page 73)
Strategy
Annual Report (page 12) and Sustainability Report (pages 4-5) and
our Energy Outlook (pages 3-5)
Risk management
Annual Report (page 55)
Metrics and targets
Sustainability Report (pages 6 and 14)
Reporting on 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 and
steam.
There was a slight decrease in our direct GHG emissions in 2017. The
primary reasons for this include operational changes such as planned
shutdowns at several of our refineries for maintenance, and actions
taken by our businesses to reduce emissions in areas such as flaring,
methane and energy efficiency.
Greenhouse gas emissions (MteCO2e)
Operational controla
Direct emissions
Indirect emissions
BP equity shareb
Direct emissions
Indirect emissions
2017
2016
2015
50.5
6.1
49.4
6.8
51.4
6.2
50.1
6.2
51.2
7.0
49.0
6.9
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 BP equity share comprises our share of BP’s consolidated entities and equity-accounted
entities, other than BP’s share of Rosneft.
The ratio of our total GHG emissions reported on an operational control
basis to gross production was 0.24teCO2e/te production in 2017 (2016
0.24 teCO2e/te, 2015 0.24teCO2e/te). Gross production comprises
upstream production, refining throughput and petrochemicals produced.
Our approach to reporting GHG emissions broadly follows the IPIECA/
API/IOGP Petroleum Industry Guidelines for Reporting GHG Emissions.
We calculate CO2 emissions based on the fuel consumption and fuel
properties for major sources. 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.
50
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BP Annual Report and Form 20-F 2017
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Managing our environmental and
social impacts
We assess potential impacts through the
life of our operations.
Above: Uncovering a cultural heritage site in Azerbaijan.
In planning our projects, we identify actions we need to take to address
potential impacts from our activities in areas such as labour rights,
water use and protected areas. If our screening process shows that
a proposed project could enter or affect an international protected area,
we work to identify ways to first avoid, and if needed, minimize and
mitigate any potential impact.
We consult with stakeholders who may be affected by our activities. For
example, we met with more than 2,600 community members in
Mauritania and Senegal over the course of 2017 to discuss issues
ranging from local employment to our ability to respond to an oil spill.
These consultations will contribute to an environmental and social
impact assessment in 2018.
Every year, our major operating sites review their performance and set
local improvement targets. These can include measures on flaring,
greenhouse gas emissions and the use of water.
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 national and local suppliers, and through the taxes
we pay to governments. Additionally, our social investments support
communities’ efforts to increase their incomes and improve standards
of living.
As one example, we are equipping women living in rural areas of Turkey
close to the Baku-Tbilisi-Ceyhan pipeline with entrepreneurial skills so
they can set up their own businesses, or enhance existing ones. In 2017
we provided training to more than 250 women and supported around
25 start-up companies.
We run programmes to build the skills of businesses and develop the
local supply chain in a number of locations. For example, our enterprise
development programme in Azerbaijan enables local companies to build
their skills so that they can improve their competitiveness when bidding
for work with international firms. And in Indonesia we have set a target
of sourcing 38% of our services and project materials from local
suppliers for our Tangguh expansion project.
We aim to recruit our workforce from the community or country in
which we operate. In Angola, for example, around 88% of our workforce
is Angolan.
We contributed $89.5 million in social investment in 2017. One area
in which we focus our investment is education. We support science,
technology, engineering and mathematics programmes in countries
such as the UK, the US and India, to encourage more young people
to consider careers in these fields.
See bp.com/society for more information on how we generate value
to society.
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Tax and transparency
BP is committed to complying with tax laws in a responsible manner and
having open and constructive relationships with tax authorities. We paid
$5.8 billion in income and production taxes to governments in 2017
(2016 $2.2 billion, 2015 $3.5 billion).
We support transparency in the flow of revenue from oil and gas
activities to governments. Transparency helps citizens hold public
authorities to account for the way they use funds received through taxes
and other agreements.
We are a founding member of the Extractive Industries’ Transparency
Initiative (EITI), which requires disclosure of payments made to and
received by governments in relation to oil, gas and mining activity. As
part of the EITI, we work with governments, non-governmental
organizations and international agencies to improve the transparency of
payments to governments. In 2017 we supported EITI implementation
in a number of countries where we operate, including Iraq and Trinidad
& Tobago.
In addition, we disclose information on payments to governments
for our upstream activities on a country-by-country and project basis
under national reporting regulations such as those in effect in the UK.
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 are committed to respecting the rights and
dignity of all people when conducting business.
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. These include the rights of our workforce and those living in
communities affected by our activities.
We set out our commitments in our human rights policy and our code
of conduct. Our operating management system contains guidance on
respecting the rights of workers and community members.
We are aligning our business processes with the UN Guiding Principles,
which set out how companies should prevent, address and remedy
human rights impacts. Our current focus areas include the recruitment,
working and living conditions of contracted workforces at our sites,
responsible security, community grievance mechanisms and channels
for workforces to raise their concerns.
In 2017 our actions included:
• Reviewing the risk of modern slavery in prioritized locations.
• Delivering additional human rights training specifically on
modern slavery.
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BP Annual Report and Form 20-F 2017
51
• Publishing our expectations of suppliers on the way they do business
with and for BP in line with our code of conduct, including respect for
human rights.
• 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.
Environment
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. See pages 48-49 for information on our oil spill performance and
preparedness.
Water
Each year we review water risks in our portfolio – considering the local
availability, quantity, quality and regulatory requirements. We assess
different approaches for optimizing freshwater withdrawals and
wastewater treatment performance. In our gas operations in Oman – an
area where the availability of fresh water is extremely scarce – we use
saline water from a local underground aquifer. We desalinate the water
and use it for drilling and hydraulic fracturing. We continue to look for
ways in which we can reduce our demand, such as reusing treated
wastewater.
See bp.com/water for information about our approach to water.
Air quality
We put measures in place to manage our air emissions, in line with
regulations and guidelines designed to protect the health of local
communities and the environment. We are introducing six liquefied
natural gas (LNG) carriers with energy efficiency enhancements to our
shipping fleet. They are designed to use approximately 25% less fuel
and emit less nitrogen oxides than our older LNG ships.
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 that we use at each site. We also submit data
on their use in 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.
Ethical conduct
Our code of conduct defines our commitment
to high ethical standards.
Our values
Our values of safety, respect, excellence, courage and one team,
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 sets clear 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 that they feel is unsafe or
unethical 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 817 concerns or enquiries were received through OpenTalk in
2017 (2016 956, 2015 1,158). 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 2017 our businesses
dismissed 70 employees for non-conformance with our code of conduct
or unethical behaviour (2016 109, 2015 132). This excludes dismissals of
staff employed at our retail service stations.
See bp.com/codeofconduct for more information.
Anti-bribery and corruption
We operate in some of the world’s highest risk countries from an
anti-bribery and corruption perspective. 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 and procedures
include measures and guidance to assess risks, understand relevant
laws and report concerns. They apply to all BP-operated businesses.
We provide training to employees appropriate to the nature or location
of their role. A total of 12,500 employees completed anti-bribery and
corruption training in 2017 (2016 13,000, 2015 13,500).
Above: Engineers on a wind turbine at our Sherbino wind farm in Texas.
52
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Our people
BP’s success depends on having a talented and
diverse workforce.
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
2017
17,700
42,100
14,200
74,000
16,800
2016
18,700
41,800
14,000
74,500
16,200
2015
21,700
44,800
13,300
79,800
15,600
4,300
4,600
4,800
52,900
53,700
59,400
a Reported to the nearest 100. For more information see Financial Statements – Note 33.
We have reshaped our organization over the past few years to adapt to
a lower oil price environment. Our focus is on retaining the skills we
require to maintain safe and reliable operations while developing and
attracting individuals with capabilities we judge important to growing
the business in new ways.
The group people committee helps facilitate the group chief executive’s
oversight of policies relating to employees. In 2017 the committee
discussed remuneration policy, progress in our diversity and inclusion
programme, modernizing and strengthening our attractiveness as an
employer, and long-term people priorities.
Attraction and retention
A total of 314 graduates joined BP in 2017 (2016 231, 2015 298). We
were named the UK’s leading recruiter in the oil and gas sector in The
Times newspaper’s Graduate Employer rankings in 2017.
We invest in our employees’ development – with an average spend of
around $3,300 per person. This includes online and classroom-based
courses and resources, supported by a wide range of on-the-job learning
and mentoring programmes.
Diversity
We are committed to making our workplaces reflect the communities in
which we are based.
The gender balance across BP as a whole is steadily improving, with
women representing 34% of BP’s total population (2016 33%, 2015
32%). We are working to improve these numbers further by, for
example, developing mentoring, sponsorship and coaching programmes
to help more women advance. That said, we still have work to do at the
executive and senior levels.
We have published 2017 data on our gender pay gap in the UK at
bp.com/ukgenderpaygap.
Above: A team meeting at the BP office in Baku, Azerbaijan.
We assess any exposure to bribery and corruption risk when working
with suppliers and business partners. Where appropriate, we put in
place a risk mitigation plan or we reject them if we conclude that risks
are too high.
We also conduct anti-bribery compliance audits on selected suppliers
when contracts are in place. For example, our upstream business
conducts audits for a number of suppliers in higher-risk regions to
assess their compliance with our anti-bribery and corruption contractual
requirements. Potential areas for improvement are shared with our
suppliers and we often work with them to find the best ways to
strengthen their procedures, such as improvements to training and
management of subcontractors. We issued a total of 36 audit reports in
2017 (2016 25, 2015 35). We take corrective action with suppliers and
business partners who fail to meet our expectations, which may include
terminating contracts.
Lobbying 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 and these rights are governed by the applicable laws in the
countries in which we operate. For example, in the US we provide
administrative support for 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 with federal and state law and
are publicly reported in accordance with US election laws.
We work with governments on a range of issues that are relevant to
our business, from regulatory compliance, to understanding our tax
liabilities, to collaborating on community initiatives. The way in which we
interact with those governments depends on the legal and regulatory
framework in each country.
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BP Annual Report and Form 20-F 2017
53
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.
At the end of 2017 there were three female directors (2016 3, 2015 3)
on our board of 13. Our nomination committee remains mindful of
diversity when considering potential candidates.
For more information on the composition of our board, see page 73.
Workforce by gender
Members as at 31 December
Board directors
Group leaders
Subsidiary directors
All employees
Male
10
310
1,155
48,795
Female
3
84
218
25,239
Female %
23
21
16
34
We are also committed to increasing the national diversity of our
workforce to reflect the countries in which we operate. A total of 24%
of our group leaders came from countries other than the UK and
the US in 2017 (2016 23%, 2015 21%).
Inclusion
Our goal is to create an environment of inclusion and acceptance, where
everyone is treated equally and without discrimination.
To promote an inclusive culture we provide leadership training and
support employee-run advocacy groups in areas such as gender, sexual
orientation and parenting. As well as bringing employees together, these
groups support BP’s recruitment programmes and provide feedback on
the potential impact of policy changes. Each group is sponsored by a
senior executive.
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 BP’s performance, and seek to maintain constructive relationships
with labour unions formally representing our employees.
Each year, we survey our employees to gauge how they feel about BP.
The overall employee engagement score in 2017 was 73% – up from
two years ago when we saw a decline which coincided with the
uncertainties of a low oil price environment.
Pride in working for BP increased to 75% in 2017, compared with 73% in
2016 and 68% in 2015. Scores for diversity, inclusion and respect also
recorded strong improvements. We are considering how to address
employee dissatisfaction with opportunities to develop their skills –
which had lower scores in 2017.
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BP Annual Report and Form 20-F 2017
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How 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 57.
Oversight and governance – throughout the year functional
leadership, the executive team, the board and relevant committees
provide oversight of how significant risks to BP are identified, assessed
and managed. They help to ensure that risks are governed by relevant
policies and are managed appropriately.
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:
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 oversight and governance
Key risk oversight and governance committees include the following:
• Understand the risk environment, identify the specific risks and assess
Executive committees
the potential exposure for BP.
• Determine how best to deal with these risks to manage overall
potential exposure.
• Manage the identified risks in appropriate ways.
• 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
• Monitor and seek assurance of the effectiveness of the management
and cyber risks.
of these risks and intervene for improvement where necessary.
• Group disclosure committee – for financial reporting risks.
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• 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.
See Board activity in 2017 on page 72, committee reports on
pages 77-89 and Risk management and internal control on
page 113.
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 impact and likelihood, and
to inform how we prioritize specific risk management activities and
invest resources to manage them.
• 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 these safe, compliant and
reliable operations as well as greater efficiency and sustainable financial
results.
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.
Book 1.indb 55
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BP Annual Report and Form 20-F 2017
55
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 high priority risks for particular oversight by the board and its
various committees in the coming year. Those identified for 2018 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, for example technological
change or the transition to a lower carbon economy, is undertaken in the
normal course of business and in the executive team, the board and
relevant committees.
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 operating management system 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.
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 57.
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 continue to monitor
threats globally and maintain disaster recovery, crisis and business
continuity management plans.
Compliance and control risks
Ethical misconduct and legal or regulatory non-compliance
Ethical misconduct or breaches of applicable laws or regulations could
damage our reputation, adversely affect operational results and
shareholder value, and potentially affect our licence to operate.
Our code of conduct and our values and behaviours, applicable to all
employees, are central to managing this risk. Additionally, we have
various group requirements 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
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.
Risks for particular oversight by the board and its
committees in 2018
The risks for particular oversight by the board and its committees in
2018 have been reviewed and updated. These risks remain the same
as for 2017.
Strategic and commercial risks
Financial liquidity
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, global
economic conditions and the influence of OPEC.
We seek to 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 manage this risk through development and maintenance of
relationships with governments and stakeholders and by becoming
trusted partners in each country and region. In addition, we closely
monitor events and implement risk mitigation plans where appropriate.
Cyber security
The targeted and indiscriminate threats to the security of our digital
infrastructure continue to evolve rapidly and are increasingly prevalent
across industries worldwide. The oil and gas industry is subject to
evolving risks from a variety of cyber threat actors, including nation
states, criminals, terrorists, hacktivists and insiders. A cyber security
breach could disrupt our business, injure people, harm the environment
or our assets, or result in legal or regulatory breaches.
We seek to manage this risk through a range of measures, which
include cyber security standards, security protection tools, ongoing
detection and monitoring of threats and testing of cyber response and
recovery procedures. We collaborate closely with governments, law
enforcement agencies and industry peers to understand and respond to
new and emerging cyber threats. We build awareness with our staff,
share information on incidents with leadership for continuous learning
and conduct regular exercises including with the executive team to test
response and recovery procedures.
56
See Glossary
BP Annual Report and Form 20-F 2017
Book 1.indb 56
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Risk factors
The risks discussed below, separately or in combination, could have
a material adverse effect on the implementation of our strategy, our
business, financial performance, results of operations, cash flows,
liquidity, prospects, shareholder value and returns and reputation.
Strategic and commercial risks
Prices and markets – our financial performance is impacted by
fluctuating prices of oil, gas and 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 – exposure to a range of political developments and
consequent changes to the operating and regulatory environment
could cause business disruption.
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 trade restrictions and other
sanctions, could adversely impact our income and investment in or
relating to Russia. Our ability to pursue business objectives and to
recognize production and reserves relating to these investments 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 or work within our financial framework
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 also 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 251 and Financial statements – Note 27.
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Joint arrangements and contractors – varying levels of control
over the standards, operations and compliance of our partners,
contractors and sub-contractors could result in legal liability and
reputational damage.
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 cyber security – breach of our digital
security or failure of our digital infrastructure including loss or misuse of
sensitive information could damage our operations, increase costs and
damage our reputation.
The oil and gas industry is subject to fast-evolving risks from cyber threat
actors, including nation states, criminals, terrorists, hacktivists and
insiders. A breach or failure of our digital infrastructure – including control
systems – due to breaches of our cyber defences, or those of third
parties, negligence, intentional misconduct or other reasons, could
seriously disrupt our operations. This 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
legal liability. Furthermore, the rapid detection of attempts to gain
unauthorized access to our digital infrastructure, often through the use
of sophisticated and co-ordinated means, is a challenge and any delay
or failure to detect could compound these potential harms. These could
result in significant costs including the cost of remediation or
reputational consequences.
Climate change and the transition to a lower carbon economy –
policy, legal, regulatory, technology and market change related to the
issue of climate change could increase costs, reduce demand for our
products, reduce revenue and limit certain growth opportunities.
Changes in laws, regulations, policies, obligations, social attitudes and
customer preferences relating to the transition to a lower carbon
economy could have a cost impact on our business, including increasing
compliance and litigation costs, and could impact our strategy. Such
changes could lead to constraints on production and supply and access
to new reserves. Technological improvements or innovations that
support the transition to a lower carbon economy, and customer
preferences or regulatory incentives related to such changes that alter
fuel or power choices, such as towards low emission energy sources,
could impact demand for oil and gas. Depending on the nature and
speed of any such changes and our response, this could adversely
affect the demand for our products, investor sentiment, our financial
performance and our competitiveness. See Climate change on
page 50.
Competition – inability to remain efficient, maintain a high quality
portfolio of assets, 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, manufacturing, renewable energy or
new technologies lags the industry. Our performance could also be
negatively impacted if we fail to protect our intellectual property.
Book 1.indb 57
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BP Annual Report and Form 20-F 2017
See Glossary
57
Compliance and control risks
US government settlements – failure to comply with the terms of our
settlement with the US Environmental Protection Agency 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.
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 growth 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, we may be subjected to a higher level of fines or penalties
imposed in relation to any alleged breaches of laws or 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 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, fines and
potentially damaging our reputation. See Financial statements –
Note 27.
Reporting – failure to accurately report our data could lead to regulatory
action, legal liability and reputational damage.
External reporting of financial and non-financial data, including reserves
estimates, relies on the integrity of systems and people. Failure to report
data accurately and in compliance with applicable standards could result
in regulatory action, legal liability and damage to our reputation.
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 – failure to address an
incident effectively could potentially disrupt our business.
Our business activities could be disrupted if we do not respond, or are
perceived not to respond, in an appropriate manner to any major crisis or
if we are not able to restore or replace critical operational capacity.
Insurance – our insurance strategy could expose the group to material
uninsured losses.
BP generally purchases insurance only in situations where this is legally
and contractually required. 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 –
exposure to a wide range of health, safety, security and environmental
risks could result in regulatory action, legal liability, business interruption,
increased costs, damage to our reputation and potentially denial of our
licence to operate.
Technical integrity failure, natural disasters, extreme weather or a
change in its frequency or severity, human error and other adverse
events or conditions could lead to loss of containment of hydrocarbons
or other hazardous materials or constrained availability of resources used
in our operating activities, 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 and
security on page 47.
Such events or conditions, 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. As a result we could 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 or conditions could be greater than in other locations.
Drilling and production – challenging operational environments and
other uncertainties could impact drilling and production activities.
Our activities require high levels of investment and are sometimes
conducted in challenging environments such as those prone to natural
disasters and extreme weather, which heightens the risks of technical
integrity failure. 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
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 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.
58
See Glossary
BP Annual Report and Form 20-F 2017
The Strategic report was approved by the board and signed on its behalf
by David J Jackson, company secretary on 29 March 2018.
Book 1.indb 58
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Corporate
governance
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60 Board of directors
66 Executive team
68 Executive management teams
70
Introduction from the chairman
71 Governance framework
71 Board and committee attendance
72 Board activity in 2017
72 Role of the board
73 Skills and expertise
73 Diversity
73
73 Appointment and time commitment
74 Training and induction
74 Board evaluation
75 Site visits
Independence
76 Shareholder engagement
Institutional investors
76
76 Private investors
76 AGM
76 UK Corporate Governance Code compliance
76
International advisory board
77 Committee reports
77 Audit committee
84
86 Remuneration committee
87 Geopolitical committee
88 Chairman’s committee
89 Nomination committee
Safety, ethics and environment assurance committee
90 Directors’ remuneration report
93 Summary of pay and performance
94 Summary of policy approach
95 Single figure table
96 Alignment with strategy
98 Pay and performance for 2017
102 Implementation of policy for 2018
105 Stewardship
107 Non-executive directors
108 Executive directors’ interests
110 Policy summary tables
113 Directors’ statements
113 Statement of directors’ responsibilities
113 Risk management and internal control
114 Longer-term viability
114 Going concern
114 Fair, balanced and understandable
Book 1.indb 59
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BP Annual Report and Form 20-F 2017
BP Annual Report and Form 20-F 2017
59
59
Board of directors
As at 29 March 2018
See BP’s board governance principles relating
to director independence on page 275.
Carl-Henric Svanberg
Chairman
Bob Dudley
Group chief executive
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
Ian Davis
Senior 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
Member of the remuneration,
geopolitical, nomination and
chairman’s committees
Professor Dame Ann Dowling
Independent non-executive
director
Melody Meyer
Independent non-executive
director
Brendan Nelson
Independent non-executive
director
Paula Rosput Reynolds
Independent non-executive
director
Chair of the remuneration
committee; member of the
SEEA, nomination and
chairman’s committees
Member of the SEEA, geopolitical
and chairman’s committees
Chair of the audit committee;
member of the chairman’s and
remuneration committees
Member of the audit, chairman’s
and remuneration 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
60
BP Annual Report and Form 20-F 2017
a Safety, ethics and environment
assurance
Book 1.indb 60
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Carl-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 65 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 has
successfully led the board for the past eight years and has announced
his intention to stand down before the AGM in 2019.
Carl-Henric’s performance has been evaluated by the chairman’s
committee, led by Ian Davis.
Bob Dudley
Group chief executive
Tenure
Appointed to the board 6 April 2009
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. 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. Bob continues to lead the development
of the group’s strategy, as we adapt to the challenges of the transition to a
lower carbon economy. Under Bob’s leadership, BP successfully delivered
seven major projects in 2017.
Bob Dudley’s performance has been considered and evaluated by the
chairman’s committee.
Brian Gilvary
Chief financial officer
Tenure
Appointed to the board 1 January 2012
Outside interests
• Non-executive director and member of audit committee
of L’Air Liquide
• Non-executive director and vice chair of audit committee
of the Navy Board
• Vice chair of the 100 Group Committee
• Member of Trilateral Commission
• Visiting professor at Manchester University
• Great Britain Age Group triathlete
Age 56 Nationality British
Outside interests
• Fellow of the Royal Academy of Engineering
• 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
Age 62 Nationality American and British
Career
Brian Gilvary was appointed chief financial officer on 1 January 2012.
The role includes responsibility for finance, tax, treasury, mergers
and acquisitions, investor relations, audit, global business services,
information technology and procurement. He also has accountability for
both integrated supply and trading, and the shipping division responsible
for BP's tanker fleet.
Brian joined BP in 1986 after obtaining a PhD in mathematics from the
University of Manchester. Following a broad range of roles in upstream,
downstream and trading in Europe and the US, he became downstream’s
commercial director from 2002 to 2005. From 2005 until 2009 he was
chief executive of the integrated supply and trading function, BP’s
commodity trading arm. In 2010 he was appointed deputy group chief
financial officer with responsibility for the finance function.
BP Annual Report and Form 20-F 2017
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He was a director of TNK-BP over two periods, from 2003 to 2005 and
from 2010 until the sale of the business and BP’s acquisition of Rosneft
equity in 2013. He served on the HM Treasury Financial Management
Review Board from 2014 to 2017.
Relevant skills and experience
Brian Gilvary has spent his entire career with BP. Brian has broad
experience across the group which gives 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 where trading is a key creator of value.
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. Brian has been at the centre
of the group’s work on addressing cyber risk.
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
• Chairman of Unifeeder Group A/S
• Chairman of Faerch Plast A/S
Age 59 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 has been nominated for election as a member
and chairman of the supervisory board of Akzo Nobel N.V. following his
successful appointment at their AGM in April 2018.
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, having led global corporations with integrated operations
worldwide. He has substantial skill, knowledge and experience
in marketing, brand and reputation issues. He has broad shipping
and upstream energy industry experience which aligns with BP’s
shipping business. His leadership earlier in his career focused on the
transformation of businesses, 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 73 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.
Paul Anderson will be retiring from the board at the 2018 AGM in May.
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 69 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.
62
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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 the energy sector. He has
been involved in delivering very large projects particularly in the energy
industry. 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 through the ‘Partnering Against Corruption’ initiative.
This overall experience makes Alan ideal to lead the SEEAC. His
remuneration experience on other boards means that he makes a
strong contribution to the remuneration committee.
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 73 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.
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 holds two masters degrees
in engineering from the Massachusetts Institute of Technology. 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.
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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. Frank makes a substantial contribution to
the safety culture within BP. 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 an important
perspective to the board and the SEEAC. He has led the oversight of BP’s
compliance with the agreements with the US government stemming from
the Deepwater Horizon accident.
Frank’s experience of the US and global political and regulatory systems is
a valuable asset to the geopolitical committee.
Ian Davis
Senior 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 67 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 global 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. He is
able to draw on knowledge of diverse issues and outcomes to assist the
board and its committees.
Ian led the board’s oversight of the response in the Gulf and chaired the
Gulf of Mexico committee from its formation in 2010 until it was stood
down in 2016. He was previously a non-executive director in the Cabinet
Office giving him an important perspective on government affairs which
is an asset to both the board and the geopolitical committee.
In his role as the senior independent director, Ian is responsible for the
annual evaluation of the chairman’s performance and is leading the
search for the successor to the chairman.
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BP Annual Report and Form 20-F 2017
63
Professor Dame Ann Dowling
Independent non-executive director
Tenure
Appointed 3 February 2012
Melody Meyer
Independent non-executive director
Tenure
Appointed 17 May 2017
Board and committee activities
Chair of the remuneration committee; member of the safety, ethics
and environment assurance, nomination and chairman’s committees
Board and committee activities
Member of the safety, ethics and environment assurance, geopolitical
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 65 Nationality British
Outside interests
• President of Melody Meyer Energy LLC
• Director of the National Bureau of Asian Research
• Trustee of Trinity University
• Non-executive director of AbbVie Inc.
• Senior Advisor to Cairn India Limited
• Non-executive director of National Oilwell Varco, Inc.
Age 60 Nationality American
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 council.
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, the Chinese Academy of Engineering and the French
Academy of Sciences. She has honorary degrees from 15 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.
Following an extensive consultation, a revised remuneration policy was
approved by shareholders at the 2017 AGM. This was a direct result of
Dame Ann's leadership of the committee. Dame Ann will hand the chair
of the committee to Paula Reynolds after the 2018 AGM.
Career
Melody Meyer started her career with Gulf Oil in Houston. Gulf Oil
later merged with Chevron where Melody remained until her retirement
in 2016.
During her career with Chevron, Melody had key leadership roles in
global exploration and production, working on international projects and
operational assignments. In 2004 Melody became the vice president
for the Gulf of Mexico business unit, and in 2008 became president
of the Chevron Energy Technology Company. From 2011 Melody was
president of Asia Pacific Exploration and Production, responsible for
the financial and operating performance of the upstream assets in nine
countries in Chevron’s Asia Pacific region. Melody was the executive
sponsor of the Chevron Women’s Network and continues as a mentor
and advocate for the advancement of women in the industry. She was
recognized as a 2009 Trinity Distinguished Alumni, with the BioHouston
Women in Science Award, was the ASME Rhodes Petroleum Industry
Leadership Award recipient and in 2018 as an Influential Woman
in Energy.
Relevant skills and experience
Melody Meyer has spent her entire career in the oil and gas industry.
The breadth, variety and geographic scope of her experience is
distinctive. Her career has been marked by a focus on excellence, safety
and performance improvement. She has expertise in the execution
of major capital projects, creation of businesses in new countries,
strategic and business planning, merger integration and safe and reliable
operations.
Melody brings a world class operational perspective to the board, with
a deep understanding of the factors influencing safe, efficient and
commercially high-performing projects in a global organization.
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 and
remuneration committees
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 68 Nationality British
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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
Brendan Nelson has completed a wide variety of audit, regulatory and
due-diligence engagements over the course of his career. 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. He brings related input
from his role as the chair of the audit committee of a major bank. His
specializm in the financial services industry allows him to contribute
insight into the challenges faced by global businesses by regulatory
frameworks.
Brendan led the successful tendering of BP’s audit services and
joined the remuneration committee in 2017.
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 61 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 and deep
experience of trading 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.
Paula joined the remuneration committee in 2017. Paula currently serves
as the chair of the remuneration committee of BAE Systems
Ltd and will take the chair of BP’s remuneration committee after the
2018 AGM.
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 62 Nationality British
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Career
Sir John Sawers spent 36 years in public service in the UK, working on
foreign policy, international security and intelligence.
Sir 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 adviser to the Prime
Minister (1999-01). Earlier in his career, he was posted to Washington,
South Africa, Syria and Yemen.
Sir 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
geopolitical 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.
David Jackson
Company secretary
Tenure
Appointed 2003
David Jackson, a solicitor, is a director of BP Pension Trustees Limited.
The ages of the board are
correct as at 29 March 2018.
BP Annual Report and Form 20-F 2017
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Executive team
As at 29 March 2018
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
• Member of the Strategic
Advisory Board of the University
of Surrey
Age 58 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 54 Nationality American
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 60 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
• Fellow of the Energy Institute
Age 47 Nationality Irish
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.
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.
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.
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.
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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 61-65) and the senior management listed on
these pages. The ages of the executive team are correct as at 29 March 2018.
Lamar McKay
Deputy group chief executive
Executive team tenure
Appointed 16 June 2008
Outside interests
No external appointments
Age 59 Nationality American
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
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.
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• Member of the Accenture Global Energy Board
• Member, International Advisory Board of the Ministry of Petroleum
and Natural Gas, Government of India
• Member of the Board of Advisors of the Fletcher School of Law and
Diplomacy, Tufts University
Age 52 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.
Eric Nitcher
Group general counsel
Executive team tenure
Appointed 1 January 2017
Outside interests
No external appointments
Age 55 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.
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 57 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.
Outside of his role, Helmut is a non-executive director of Ivoclar
Vivadent. Additionally, he is an alumni and advocate of AFS, an
international exchange organization.
Book 1.indb 67
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BP Annual Report and Form 20-F 2017
67
Executive management teams
Upstream
1. Andy Hopwood
Chief operating officer,
strategy and regions
2. James Dupree
Chief operating officer,
developments and technology
3. Kerry Dryburgh
Head of human resources
4. Tony Brock
Head of safety and
operational risk
5. Bernard Looney
Chief executive
6. Murray Auchincloss
Chief financial officer
7. Nigel Jones
Associate general counsel
8. Gordon Birrell
Chief operating officer, production,
transformation and carbon
2
4
5
6
8
1
3
7
Other business and functions leaders
1. David Eyton
Group head of technology
2. Dominic Emery
Vice president, group
strategic planning
3. Laura Folse
Chief executive officer,
wind, alternative energy
4. Richard Hookway
Chief operating officer of global
business services and information
technology and systems
7. Dev Sanyal
Chief executive, alternative
energy and executive
vice president, regions
5. David Jardine
Group head of audit
6. Robert Lawson
Global head of mergers
and acquisitions
8. Joan Wales
Head of safety and operational
risk, alternative energy
9. Craig Marshall
Group head of investor relations
10. Spencer Dale
Group chief economist
11. Geoff Morrell
Group head of communications
and external affairs
12. Lucy Knight
Human resources vice president,
corporate business activities
and functions
13. Trudi Charles
Associate general counsel,
integrated supply and trading
5
6
8
13
12
68
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Downstream
1. Rita Griffin
Chief operating officer,
petrochemicals
2. Mike O’Sullivan
Chief financial officer
3. Michael Sosso
Associate general counsel,
downstream and BP shipping
Our diverse and talented leaders have a wide range of skills
and disciplines that support our executive team’s work. These
include experts in fields such as renewable energy, finance,
trading, technology and digital, and tax and treasury. Job titles
correct as at 1 January 2018.
4. Doug Sparkman
Chief operating officer,
fuels, North America
5. Angela Strank
Head of technology and
BP chief scientist
6. Tufan Erginbilgic
Chief executive
7. Mandhir Singh
Chief operating officer,
lubricants
8. Evelyn Gardiner
Head of human resources
9. Guy Moeyens
Chief operating officer, fuels,
Europe and Southern Africa
10. Andy Holmes
Chief operating officer,
fuels ASPAC and Air BP
1
3
4
6
7
9
C
C
o
o
r
r
p
p
o
o
r
r
a
a
t
t
e
e
g
g
o
o
v
v
e
e
r
r
n
n
a
a
n
n
c
c
e
e
2
5
8
10
14. David Anderson
Chief financial officer,
alternative energy
15. Ashok Pillai
Vice president, group reward
16. Kate Thomson
Group treasurer
17. Rahul Saxena
Group ethics and compliance officer
20. Jan Lyons
Group head of tax
18. Mario Lindenhayn
Chief executive officer, biofuels,
alternative energy
21. Alan Haywood
Chief executive officer, integrated
supply and trading
19. Susan Dio
Chief executive officer, shipping
22. William Lin
Head of group chief executive’s office
23. Carol Howle
Head of group chief executive’s office
24. Camille Drummond
Head of global
business services
25. David Bucknall
Group controller and chief financial
officer, other businesses and corporate
26. Nick Wayth
Chief development officer,
alternative energy
16
18
22
24
BP Annual Report and Form 20-F 2017
25
69
Book 1.indb 69
03/04/2018 16:43:50
Introduction from the chairman
The board has a clear focus
on the issues that are crucial
to the long-term sustainability
of the company.
The work of the board continued to progress in 2017. We
focused on the development and implementation of our
strategy out to 2021 that we communicated to investors
last year. We have seen substantial variations in the oil
price and have had to ensure that BP is robust for all
financial cycles.
We believe there will be a continuing demand for
hydrocarbons over the coming decades. Our strategy is
designed to balance our role in supplying energy for the
world with the growing need to be part of the transition
to a lower carbon global economy. The board’s focus has
been on this dual challenge, which is crucial to the
company’s long-term sustainability.
The role of business in society remains a major issue
which all boards must address. In the UK, the Financial
Reporting Council has published its consultation on a
material revision to the UK Corporate Governance Code.
There is a clear emphasis on the need for boards to focus
on their relationship with all those with whom the
company comes into contact. In particular, boards are
encouraged to ensure they find ways to hear the voice
of the employee in the board room.
We are participating in this consultation and have already
established a variety of ways to speak and listen to our
employees around the world. We will need to ensure that
all voices – those of shareholders, employees, customers
and communities – find their way to the board. Our
long-term investments and relationships in many
countries have already helped with this.
Remuneration continued to be an area of focus in the
year. We are grateful to our shareholders for their support
of the remuneration report at the 2017 AGM. This was
very important to us. The remuneration committee
continued its work this year, as it implements the new
policy and some legacy awards from the 2014 policy. The
committee has again had some challenging decisions to
take. Dame Ann Dowling will be standing down from the
committee at the 2018 AGM after three years in the
chair. I would like to thank her and pay tribute to her work.
Paula Reynolds, already an experienced remuneration
committee chair, will succeed Dame Ann.
I will be standing down as chairman at an appropriate
time after the 2018 AGM. Ian Davis, the senior
independent director, has already begun the search for
my successor. I will have served as chairman for almost
nine years by the time I stand down.
The board has faced and risen to many challenges during
that time and membership has evolved and remained
balanced. I believe that we are well placed for the future
– with the appropriate mix of skills, experience and
diversity. Throughout I have wanted to ensure that we
used our time wisely as it was essential that we had
the space in our meetings to discuss strategy and the
direction of the company. In 2010 we formed the Gulf of
Mexico committee, originally to have oversight of our
commitment on the ground following the accident. The
work of this committee evolved into considering the
reports on the causes of the accident and subsequently
leading the work around the ensuing litigation. The
committee sat for five years. We also formed a special
committee to oversee negotiations in Russia which
eventually led to our equity ownership in Rosneft. This
experience led to the formation of the geopolitical
committee which is now well in its stride.
We have used the evaluations of the board and the
committees to ensure that we have been focusing on the
right issues and adding value. I am pleased that over the
summer we will be carrying out an externally facilitated
evaluation, which I am sure will assist my successor.
I am very grateful to Bob, his executive colleagues and all
my fellow directors for all the work that they have done
during the year. BP has an exciting future and we have
the right team to take advantage of the opportunities that
it will bring.
Carl-Henric Svanberg
Chairman
70
BP Annual Report and Form 20-F 2017
Book 1.indb 70
03/04/2018 16:43:50
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 89
Remuneration
committee
See page 86
Chairman’s
committee
See page 88
SEEAC
See page 84
Geopolitical
committee
See page 87
Audit
committee
See page 77
D
e
l
e
g
a
t
i
o
n
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)
y
t
i
l
i
b
a
t
n
u
o
c
c
A
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
C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
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e
Board and committee attendance in 2017
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
Cynthia Carroll
Ian Davis
Ann Dowling+
Melody Meyer
Brendan Nelson+
Paula Rosput Reynolds
John Sawers+
Andrew Shilston
Executive directors
Bob Dudley
Brian Gilvary
A
11
11
11
11
11
5
11
11
6
11
11
11
5
A
11
11
B
11
11
11
10
11
5
11
11
6
11
10
11
4
B
11
11
A
B
A
B
A
B
A
B
A
B
A
B
A
B
13
13
13
13
5
13
13
5
6
6
6
2
6
4
6
6
6
6
1
6
4
6
4
4
4
4
1
4
3
4
4
4
1
4
4
4
4
1
4
3
4
3
4
1
8
8
8
4
2
4
3
3
1
3
2
3
1
7
8
8
4
2
4
3
3
0
3
2
3
1
3
3
3
3
1
7
10
10
10
3
10
10
7
10
10
10
3
3
3
3
3
1
7
10
10
10
2
10
10
7
10
9
10
3
A = Total number of meetings the director was eligible to attend.
B = Total number of meetings the director did attend.
+ Committee chair.
Nils Andersen did not attend meetings of the chairman’s committee when succession
was discussed.
Alan Boeckmann missed the telephone meetings of the board and remuneration
committee that had been called at short notice, due to a clash with another board.
Paula Reynolds missed a board, joint audit-SEEAC and chairman’s committee meeting
due to travel arrangements.
Cynthia Carroll missed a SEEAC, geopolitical committee and chairman’s committee meeting
due to a clash with an external commitment.
Andrew Shilston missed a board meeting immediately prior to the 2017 AGM as he was retiring
from the board.
BP Annual Report and Form 20-F 2017
71
Book 1.indb 71
03/04/2018 16:43:51
Board activity in 2017
Role of the board
The board is responsible for the overall conduct of the group’s business. 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
1
of 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
During the year the board
provided input on the group’s
strategy to senior management.
This included a two-day strategy
session in September where it
examined developments in the
wider environment and debated
strategic themes relating to BP’s
segments, key functions and the
impact of the lower carbon
transition on the group’s
business model. The board
discussed the transition to a
lower carbon world frequently
during the year.
Risk
The board, either directly
or through its monitoring
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
as part of the review of the
BP Annual Report and Form
20-F 2017.
• Identification and allocation
of risks to the board and
monitoring committees (the
audit, SEEA and geopolitical
committees) for 2017, and
confirmation of the schedule
for oversight.
It received regular reports on the
progress and implementation of
the strategy – through updates
from management and by
means of a strategic
performance scorecard which
is discussed at each full board
meeting.
The board monitored the
company’s performance against
the annual plan for 2017 and
approved the forward
framework for the annual plan
in 2018.
The board reviewed the BP
Energy Outlook, updated
in February 2018, which looks at
long-term energy trends and
projections for world energy
markets.
The board reviewed the group
risk of cyber security in 2017
– with the audit committee and
SEEAC assessing elements of
cyber security risk in their work
programme for the year. The
allocation of the group cyber
security risk to the board (with
additional monitoring by the
audit and SEEA committees)
remains unchanged for 2018.
The group risks allocated to the
committees for review over the
year are outlined in the reports
of the committees on pages
77-89.
Further information on BP’s
system of risk management is
outlined in How we manage risk
on page 55. Information about
BP’s system of internal control is
on page 113.
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.
• Quarterly and full-year results.
• Shareholder distributions.
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 leaving
unexpectedly.
The board employs executive
search firms when it concludes
that this is an effective way of
finding suitable candidates. In
2017 we appointed Egon Zehnder
to assist in the search for
non-executive directors.
The board reviews the quarterly
and full-year results, including
the shareholder distribution
policy. The 2017 annual report
was 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
culture around our global
operations.
• Cynthia Carroll and Andrew
Shilston stood down from
the board at the 2017 AGM.
• Melody Meyer was elected
as a director at the 2017 AGM.
On appointment she joined
the SEEA and geopolitical
committees.
• Brendan Nelson and Paula
Reynolds joined the
remuneration committee in
May and September 2017
respectively.
• Paul Anderson will retire
from the board at the 2018
AGM.
• Ann Dowling will step down
from the remuneration
committee after the
2018 AGM, having served
three years as chair, and
Paula Reynolds will then
assume the role.
72
BP Annual Report and Form 20-F 2017
Book 1.indb 72
03/04/2018 16:43:51
Skills and expertise
In order to carry out its duties on behalf of shareholders, the board needs to manage its non-executive 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
Non-executive director Background
Oil & gas/
extractives/
energy
Engineering/
technology
Financial
expertise
Safety
Brand/
marketing/
reputation
Regulatory/
government
affairs
Diversity
Female
Non
UK/US
Tenure
(years)
Nils Andersen
Paul Anderson
Alan Boeckmann
Frank Bowman
Ian Davis
Ann Dowling
Melody Meyer
Brendan Nelson
Paula Reynolds
John Sawers
Carl-Henric Svanberg
2
8
4
7
8
6
1
7
3
3
9
C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
n
c
e
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.
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 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.
At the end of 2017, there were three female directors (2016 3, 2015 3)
on our board of 13. Our nomination committee actively considers
diversity in seeking potential candidates for appointment to the board.
The board looked at gender and wider diversity across the group as part
of its annual review of HR, capability and talent management.
The remuneration committee and the board reviewed and discussed
BP’s data and report on the UK gender pay gap prior to its publication in
February 2018. Focus was given to the data in the report, and what
action BP is taking to address the gap and the broader issue of diversity
within the group.
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 letter of appointment sets out the time
commitment expected of him, those 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.
Book 1.indb 73
03/04/2018 16:43:51
BP Annual Report and Form 20-F 2017
73
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 directors’ remuneration report (see page 90).
Neither the chairman nor the senior independent director are employed
as an executive of the group.
Training and induction
To help develop an understanding of BP’s business, the board continues
to build its knowledge through briefings and site visits. In 2017 the board
received training on ethics and compliance.
NEDs are expected to visit at least one business a year as part of their
learning programme. In 2017 the board visited the group’s response
information centre in Sunbury, operations of Aker in Norway and the
trading business in London. Members of the SEEAC and other directors
also visited the Cherry Point refinery in the US and the Glen Lyon FPSO
vessel in the North Sea.
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
BP executives devoted
substantial time to ensure
a high quality induction.
Melody Meyer
Non-executive director
Melody Meyer, appointed in 2017, followed a
tailored induction process, which also covered
the SEEAC and geopolitical committee. 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)
• Alternative Energy
• Strategy and planning
• Lower carbon transition
• BP’s performance relative
to its competitors.
Functional input
• Human resources, including
capability and reward
• Ethics and compliance
• Research and technology
• Investor relations
• Trading
• Communications and
corporate reporting
• Group audit
• External audit
• BP women’s network
• Legal.
SEEAC specific
• Safety and operational risk
(S&OR), BP’s operating
management system
(OMS) and environmental
performance
• Operational, safety and
environmental reporting
• Group security and crisis
management.
Geopolitical committee
specific
• BP’s regional businesses
• Government affairs.
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.
Activity following prior year evaluation
Actions arising from the 2016 evaluation and how these were
addressed included:
• Focus on implementing the strategy, in particular the opportunities
relating to the transition to a lower carbon economy: reporting on the
implementation of the strategy was further developed and as a result
the board receives updates from management and a strategic
progress report at each meeting. The board held a number of
discussions on the transition to a lower carbon economy, including a
session at the strategy away day, with further sessions scheduled for
2018. The group’s quarterly results announcement was amended in
2017 to include narrative on the implementation of strategy.
• More detailed examination of the financial performance of the
business, in particular capital allocation and returns: the board
discusses financial performance at each board meeting and reviews
the proposed disclosures and investor presentation for each quarter’s
results. A return on average capital employed measure was included
in the 2017 remuneration policy and the board reviews this as part of
its performance monitoring. A review of the group’s capital allocation
process and investment effectiveness was also held during the year.
• Obtaining a better understanding of the group’s ability to effectively
deliver the strategy, including technology, digital and big data: this
included a deep dive into technology trends and their potential impact
on the group’s business model.
• Bringing wider perspectives into the board room and gaining deeper
insight into shareholder views: the board considered output from BP’s
remuneration engagement programme as well as broader governance
issues from investor meetings held throughout the year. Feedback
from institutional investors on the group’s performance and strategy
– compiled by an independent third party – was discussed with the
board following the strategy update.
• Continued emphasis on improving operational excellence: the board
received data and commentary on BP’s operations through monthly
reports and updates from management; and operational measures
were included in the annual bonus scorecard as part of the
remuneration assessment for the year.
2017 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 including:
• Investment decisions: continue focusing on capital allocation and the
way in which investment decisions are taken.
• Longer-term vision and strategy: extend the timeframe of strategic
discussions, including challenges faced by BP’s core business and the
lower carbon transition.
• Geopolitics: consider how to further optimize the output of the work
undertaken by the board, geopolitical committee and the international
advisory board.
• Improve the board’s understanding of employees’ views: expand
the existing ways employee views are disseminated to the
board to include more local and business based feedback.
74
See Glossary
BP Annual Report and Form 20-F 2017
Book 1.indb 74
03/04/2018 16:43:51
Site visits
Non-executive directors are expected to visit at least one business per year, as part of their
learning programme. In 2017 the board visited partner operations in Tranby, Norway and BP’s
trading business in London. Members of the SEEAC and other directors visited operations in
the North Sea and Washington state, and the audit committee visited our global business
services offices in Hungary. The board met local management at each visit, and after each
one, the board or appropriate committee was briefed on the impressions gained by the
directors during the visit.
Tranby, Norway
The board visited Aker’s Tranby technology
centre near Oslo to see the manufacture
of subsea well heads and the research and
development centre. The Tranby site has
been an established centre of excellence for
subsea equipment manufacturing for over a
decade.
The board heard about the research being
undertaken in subsea trees, workover
systems and subsea pumps and saw new
digital technologies to integrate engineering
and manufacturing processes being tested.
C
o
r
p
o
r
a
t
e
g
o
v
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n
a
n
c
e
Washington state, US
Members of the SEEAC and other directors
visited the Cherry Point refinery in Blaine,
Washington in June. The visit focused on
operating procedures and safety and risk
mitigation. Investment was discussed,
including technology enhancements to
produce ultra-low sulphur diesel, increasing
logistical optionality and a coker heater
project. Other discussions included the
cultural and environmental outreach projects
in the area.
They also took a tour of the refinery, control
room, the operator training simulator and
dock area.
North Sea, UK
In July members of the SEEAC and other
directors visited Glen Lyon – the floating,
production, storage and offloading vessel
for our Quad 204 major project start-up in
the North Sea. The committee was the first
to visit the vessel following production
start-up.
Discussions on board the vessel covered
project completion and future plans
including reviews of production efficiency,
operational management, safety, risk
mitigation and OMS conformance. They
also visited key areas of the vessel
including the control room and riser tower.
Global business
services, Hungary
The audit committee visited BP’s global
business service (GBS) centre located in
Budapest in September, where
standardized business services including
finance, procurement, HR, trading
settlement and tax are delivered for
businesses across the BP group.
The committee received presentations on
the GBS strategy, business model and
controls framework. They also met local
staff across a range of job levels, including
those involved in diversity and inclusion
initiatives such as LGBT and working parent
programmes.
Integrated supply
and trading, London
Members of the board visited BP’s trading
operations in London in December to gain
an insight into the group’s approach
to trading, oil and gas market fundamentals,
risk profile and strategy. Directors received
presentations from traders and originators on
the trading floor and deepened their
understanding of the group’s oil products
and LNG business models.
BP Annual Report and Form 20-F 2017
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Shareholder engagement
Institutional investors
The company operates an active investor relations programme. 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 2017 the chair of
the remuneration committee undertook extensive engagement on
the new remuneration policy prior to the AGM in May (see the
remuneration committee report on page 86). The chair of the audit
committee and the senior independent director also held one-to-one
meetings with institutional investors during the year.
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 April 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.
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.
Shareholder engagement cycle 2017
Q1
• Fourth quarter results
• BP Energy Outlook presentation
• Strategy investor roadshows with executive
management
• US SRI meetings on remuneration
• Investor meetings on remuneration, continuing
into Q2
• SRI roadshow following the launch of the BP
Sustainability Report 2016, continuing into Q2
• Chairman and board committee chairs
meetings
• UKSA private shareholders’ meeting
• First quarter results
• Meetings with members of the Church
Investors Group and Charities Responsible
Network
• Institutional Investors Group on Climate
Change (IIGCC) meeting
• Annual general meeting
• BP Statistical Review of World Energy launch
• Downstream investor day, Pangbourne
• Second quarter results
• Investor roadshows with the group
chief executive and chief financial officer
• Third quarter results
• IIGCC meeting
Q2
Q3
Q4
Private investors
BP held a further event for private investors in conjunction with the
UK Shareholders’ Association (UKSA) in 2017. The chairman and head
of investor relations gave presentations on BP’s annual results,
strategy and the work of the board. Shareholders’ questions were
focused on BP’s activities and performance.
AGM
Voting levels decreased in 2017 to 50.8% (of issued share capital,
including votes cast as withheld), compared to 64.3% in 2016 and
62.3% in 2015. We believe this drop in vote levels was due to the late
return of BP stock on loan, with voting deadlines for some custodians
coinciding with the date that BP shares went ‘ex-dividend’. The
company is looking at future AGM voting deadlines against its
financial calendar to mitigate this event recurring.
All resolutions were passed at the meeting. 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 them on
any issues arising.
UK Corporate Governance Code compliance
BP complied throughout 2017 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 of 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 was chaired by BP’s previous chairman, the late Peter
Sutherland. Its membership in 2017 comprised Lord Patten of Barnes,
Josh Bolten, President Romano Prodi, Dr Ernesto Zedillo and Dr Javier
Solana. The chairman, chief executive and Sir John Sawers attend
meetings of the IAB. Issues discussed in 2017 included the global
economy, developments in the Middle East, political events in Latin
America and the political and economic outlook in the US. The IAB
discussed the UK’s potential exit from the European Union at both of
its meetings during 2017.
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Committee reports
Audit committee
The committee continued to review the
integrity of the group’s disclosures by
challenging and debating the
judgements made by management.
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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Chairman’s introduction
Last year’s report highlighted our monitoring of the group’s financial
performance in light of the demanding external environment. While this
focus remains, the committee has continued to review the integrity of
the group’s financial reporting by challenging and debating the
judgements made by management, including the estimates which are
made. We receive reports from management and the external auditor
each quarter highlighting significant accounting issues and judgements
and have used these to inform our debate on whether BP’s financial
reporting is ‘fair, balanced and understandable’.
In 2017 the committee focused on the effectiveness of the group audit
function. We reviewed its longer-term vision and capability and oversaw
an externally facilitated review of its performance, the results of which
we discussed in a joint session with colleagues from the SEEAC. We
will continue to focus on the actions arising from the review in 2018.
Following the 2016 tender process for the statutory audit, the
committee has overseen the transition to Deloitte from EY in time for
2018. We met with both EY and Deloitte during 2017 and monitored
Deloitte’s progress towards independence in time for their ‘shadowing’
of the 2017 year-end audit.
The committee visited one of the group’s global business service
centres, located in Budapest, enabling us to see first hand the work
undertaken by this growing part of BP’s operations and to meet local
staff. We found this direct contact added an important additional
dimension to our review and understanding, and intend to hold further
site visits in 2018.
Andrew Shilston retired from the committee in May 2017. I would like
to thank Andrew for his service to the committee, and for the challenge
and perspective he provided as a member.
Brendan Nelson
Committee chair
Members
Brendan Nelson
Nils Andersen
Paula Reynolds
Andrew Shilston
Member since November 2010
and chair since April 2011
Member since October 2016
Member since May 2015
Member since February 2012;
retired May 2017
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 he 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 Brendan may be regarded as an audit committee financial expert as
defined in Item 16A of Form 20-F.
Meetings and attendance
There were 13 committee meetings in 2017, of which six were by
teleconference. All directors attended every meeting during the period
in which they were committee members.
Regular attendees at the meetings include the chief financial officer,
group controller, chief accounting officer, group head of audit and
external auditor.
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BP Annual Report and Form 20-F 2017
77
Activities during the year
Financial disclosure
The committee reviewed the
quarterly, half-year and annual
financial statements with
management, focusing on the:
• Integrity of the group’s
financial reporting process.
• Clarity of disclosure.
• Compliance with relevant legal
and financial reporting
standards.
• Application of accounting
policies and judgements.
As part of its review, the
committee received quarterly
updates from management and
the external auditor in relation to
accounting judgements and
estimates including those relating
to the Gulf of Mexico oil spill,
recoverability of asset carrying
values and other matters.
The committee keeps under
review the frequency of reporting
during the year.
The committee reviewed the
assessment and reporting of
longer-term viability, risk
management and the system
of internal control, including the
reporting and categorization of
risk across the group and the
examination of what might
constitute a significant failing or
weakness in the system of internal
control. It also examined the
group’s modelling for stress
testing different financial and
Risk reviews
The principal risks allocated to the
audit committee for monitoring in
2017 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 external
market developments and how
BP’s trading function had
responded – including new areas
of activity and impacts on the
control environment.
operational events, and considered
whether the period covered by the
company’s viability statement was
appropriate.
The committee considered the BP
Annual Report and Form 20-F
2017 and assessed whether the
report was fair, balanced and
understandable and provided the
information necessary for
shareholders to assess the
group’s position and performance,
business model and strategy. In
making this assessment, the
committee examined disclosures
during the year, discussed the
requirement with senior
management, confirmed that
representations to the external
auditors had been evidenced and
reviewed reports relating to
internal controls. The committee
made a recommendation to the
board, who in turn reviewed the
report as a whole, confirmed the
assessment and approved the
report’s publication.
Other disclosures reviewed
included:
• Oil and gas reserves.
• Pensions and post-retirement
benefits assumptions.
• Risk factors.
• Legal liabilities.
• Tax strategy.
• Going concern.
The committee further
considered updates in the trading
function’s risk management
programme, including
compliance with regulatory
developments and activities in
response to cyber threats.
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 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 cyber security landscape,
including events in the 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 examining the
indicators associated with risk
management and barrier
performance.
Other reviews
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
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 .
BP’s principal risks are listed on
page 57.
For 2018, the board has agreed
that the committee will continue
to monitor the same four group
risks as for 2017. The group risk
financial resilience has been
renamed ‘financial liquidity’ for
2018.
Other reviews undertaken in 2017
by the committee included:
recommendations, see
page 50.
• Non-operating items (NOIs):
BP’s policy for identifying and
categorizing NOIs and an
analysis of those NOIs
impacting BP’s reported results.
• Blockchain: introduction to
blockchain technology, its
potential impacts on the oil and
gas industry and an overview of
BP’s participation and approach
to date.
• Capability and succession
in BP’s finance function,
including the group’s finance
modernization programme.
• Assessment of financial metrics
for executive remuneration:
consideration of financial
performance for the group’s
2017 annual cash bonus
scorecard and performance
share plan, including
adjustments to plan conditions
and NOIs.
• Downstream: including
strategy and strategic
progress, financial
performance, risk
management and controls,
audit findings, key litigation and
ethics and compliance findings.
• Upstream: including vision
and priorities, structure and
portfolio, financial controls and
the balance sheet, an overview
of intangible assets and a
review of the segment’s
finance organization.
• Shipping: including an overview
of BP shipping’s role and
operating model, financial
performance, strategy, risk
management and controls and
the impact of IFRS 16 (lease
accounting standard).
• Financial Stability Board's Task
Force on Climate-related
Financial Disclosures (TCFD):
the origin, purpose and work of
the TCFD along with its key
recommendations and how
BP’s existing reporting
compares to these
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In te rnal control and risk management
The committee received
quarterly reports on the findings
of group audit in 2017. It reviewed
group audit’s vision for 2020,
including the roadmap for 2017
and beyond. The committee met
privately with the group head of
audit and key members of his
leadership team.
The committee oversaw an
external review of the
effectiveness of the group audit
function, which was awarded to
Deloitte in July 2017 following a
competitive tender process.
Fieldwork and interviews with
management and board
members was completed by
September 2017 and the results
of the assessment were
reviewed at a joint meeting of
the audit and safety, ethics and
environment assurance
committees in December.
The review concluded that the
group audit function:
• Performed strongly across
Deloitte’s assessment
framework.
• Demonstrated a high level of
maturity when assessed
against internal audit functions
within large FTSE (non-
financial services) companies.
• Had a remit covering all risk
categories (financial and
operational) – a breadth seen
as leading practice.
• Had areas where continuous
improvement activity and
continued dialogue with the
business could result in an
even stronger performance.
Implementation of the agreed
actions arising from the review
will be tracked during 2018.
The audit committee also held
private meetings with the group
ethics and compliance officer
during the year.
Training
The committee held a deep dive on reserves, covering resource
definition and estimation, the group’s governance processes, areas of
focus for the regulator and how BP compared with its competitors in
terms of approach. It received technical updates from the chief
accounting officer on developments in financial reporting and
accounting policy, including IFRS 9 ‘Financial Instruments’, IFRS 15
Revenues from Contracts with Customers and IFRS 16 ‘Leases’.
Site visits
In September, the committee visited BP’s global business services
(GBS) centre in Hungary. During the visit the committee reviewed the
function’s strategy, context, and how it has grown in scope and scale.
It looked at its risk management and controls processes, including
understanding the risks around transition of activity from the business
and the standardization of global processes. It also reviewed capability
and human resources issues, including talent attraction and retention,
met a range of staff and heard about the various GBS diversity
programmes including LGBT, working parents and disability awareness.
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In December, members of the committee and wider board visited BP’s
integrated supply and trading (IST) business in London for a day that
covered oil and gas market fundamentals, finance and risk, IST’s
strategy, and presentations on oil products and LNG trading.
Accounting judgements and estimates
Areas of significant judgement considered by the committee in 2017 and how these were addressed included:
Key judgements and estimates
in financial reporting
Gulf of Mexico oil spill
BP uses judgement in relation to the
recognition of provisions relating to the
Gulf of Mexico oil spill. The timing and
amounts of the remaining cash flows are
subject to uncertainty and estimation is
required to determine the amounts
provided for.
Audit committee activity
Conclusions/Outcomes
A review of the provisioning for and
disclosure of uncertainties relating to the
Gulf of Mexico oil spill was undertaken each
quarter as part of the review of the stock
exchange announcement.
Particular focus was given to updates to the
provision related to business economic loss
(BEL) and other claims related to the Gulf of
Mexico oil spill, including the continuing
effect of the Fifth Circuit May 2017 opinion
on the matching of revenues with expenses
when evaluating BEL claims.
Following significantly higher average claims
determinations issued by the Court
Supervised Settlement Program (CSSP) in
the fourth quarter 2017 and the continuing
effect arising from the Fifth Circuit May 2017
opinion, BP recognized a post-tax charge of
$1.7 billion for BEL and other claims
associated with the CSSP.
Disclosure includes information on
remaining uncertainties.
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BP Annual Report and Form 20-F 2017
79
Key judgements and estimates
in financial reporting
Audit committee activity
Conclusions/Outcomes
Oil and natural gas accounting, including reserves
BP uses technical and commercial judgements
when accounting for oil and gas exploration,
appraisal and development expenditure and in
determining the group’s estimated oil and gas
reserves.
Held an in-depth review of BP’s policy and
guidelines for compliance with oil and gas
reserves disclosure regulation, including the
group’s reserves governance framework
and controls.
Exploration write-offs totalling $1.6 billion
were recognized during the year.
Exploration intangibles totalled $17.0 billion
at 31 December 2017.
Reserves estimates based on management’s
assumptions for future commodity prices have
a direct impact on the assessment of the
recoverability of asset carrying values reported
in the financial statements.
Judgement is required to determine whether it
is appropriate to continue to carry intangible
assets related to exploration costs on the
balance sheet.
Recoverability of asset carrying values
Determination as to whether and how much
an asset, cash generating unit (CGU) or group
of CGUs containing goodwill is impaired
involves management judgement and
estimates on uncertain matters such as future
commodity pricing, discount rates, production
profiles, reserves and the impact of inflation on
operating expenses.
Judgement is required in assessing the
recoverability of overdue receivables, and
deciding whether a provision is required.
Investment in Rosneft
Reviewed exploration write-offs as part of
the group’s quarterly due diligence process.
Received briefings on the status of
upstream intangible assets, including the
status of items on the intangibles assets
‘watch-list’.
Received the output of management’s
annual intangible asset certification process
used to ensure accounting criteria to
continue to carry the exploration intangible
balance are met.
Reviewed the group’s oil and gas price
assumptions.
Reviewed the group’s discount rates for
impairment testing purposes.
Upstream impairment charges, reversals
and ‘watch-list’ items were reviewed as
part of the quarterly due diligence process.
Reviewed the group’s credit risk
management and reporting framework,
including actual credit losses observed,
expected loss delegations and utilization
and changes in the credit portfolio quality.
The group’s long-term price assumptions for
Brent
oil, and Henry Hub gas were
unchanged from 2016.
The group’s discount rates used for
impairment testing were also unchanged.
Impairments of $1.0 billion were recorded in
the year, net of impairment reversals.
The group had $1.5 billion of receivables
which were not impaired but past due
at 31 December 2017.
Judgement is required in assessing the level of
control or influence over another entity in
which the group holds an interest.
Reviewed the judgement on whether the
group continues to have significant
influence over Rosneft.
BP has retained significant influence over
Rosneft throughout 2017 as defined by
IFRS.
BP uses the equity method of accounting for
its investment in Rosneft and BP’s share of
Rosneft’s oil and natural gas reserves is
included in the group’s estimated net proved
reserves of equity-accounted entities.
The equity-accounting treatment of BP’s
19.75% interest in Rosneft continues to be
dependent on the judgement that BP has
significant influence over Rosneft.
Considered IFRS guidance on evidence
of significant influence, including
representation on the board and
participation in policy-making processes.
Received reports from management and
the external auditor which assessed the
extent of significant influence, including
BP’s participation in decision making
through the continued service on the
Rosneft board and key board committees of
two BP-nominated directors and work on
significant transactions and projects. This
assessment considered the appointment of
two additional non-BP directors to the
Rosneft board but concluded that the
assessment of significant influence
remained unchanged.
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Key judgements and estimates
in financial reporting
Derivative contracts
In some instances, BP estimates the fair value
of derivative contracts using internal models
due to the absence of quoted market pricing or
other observable, market-corroborated data.
Judgement may also be required to determine
whether contracts to buy or sell commodities
meet the definition of a derivative.
Provisions
BP’s most significant provisions relate to
decommissioning, the Gulf of Mexico oil spill
(see above), environmental remediation
litigation.
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 many years in
the future and the exact requirements that will
have to be met when a removal event occurs
are uncertain. Assumptions are made by BP in
relation to settlement dates, technology, legal
requirements and discount rates. The timing
and amounts of future cash flows are subject
to significant uncertainty and estimation is
required in determining the amounts of
provisions to be recognized.
Pensions and other post-retirement benefits
Accounting for pensions and other post-
retirement benefits involves making estimates
when measuring the group’s pension plan
surpluses and deficits. These estimates
require assumptions to be made about
uncertain events, including discount rates,
inflation and life expectancy.
Income taxes
Computation of the group’s income tax
expense and liability, the provisioning for
potential tax liabilities and the level of deferred
tax asset recognition are underpinned by
management judgement and estimation of the
amounts which could be payable.
Audit committee activity
Conclusions/Outcomes
Received a briefing on the group’s trading
risks and reviewed the system of risk
management and controls in place,
including those covering the valuation of
derivative instruments, using models where
observable market pricing is not available.
BP has assets and liabilities of $7.1 billion and
$6.6 billion respectively recognized on the
balance sheet for derivative contracts at
31 December 2017, mainly relating to the
activities of the integrated supply and trading
function (IST).
The committee annually reviews the control
process and risks relating to the trading
business.
BP’s use of internal models to value certain
of these contracts has been disclosed in
Note 28 in the financial statements.
Received briefings on decommissioning,
environmental, asbestos and litigation
provisions, including the requirements,
governance and controls for the
development and approval of cost
estimates and provisions in the
financial statements.
Reviewed the group’s discount rates for
calculating provisions.
Decommissioning provisions of $16.1 billion
were recognized on the balance sheet at 31
December 2017.
The discount rate used by BP to determine
the balance sheet obligation at the end of
2017 was a real rate of 0.5% – based on
long-dated US government bonds.
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Reviewed the group’s assumptions used to
determine the projected benefit obligation
at the year end, including the discount rate,
rate of inflation, salary growth and mortality
levels.
The method for determining the group’s
assumptions remained largely unchanged from
2016. The values of these assumptions and a
sensitivity analysis of the impact of possible
changes on the benefit expense and obligation
are provided in Note 22.
At 31 December 2017, surpluses of $4.2
billion and deficits of $9.1 billion were
recognized on the balance sheet in relation
to pensions and other post-retirement
benefits.
Received regular updates on the group’s tax
exposures and deferred tax asset
recognition.
Deferred tax assets amounting to $4.5 billion
were recognized on the balance sheet at 31
December 2017.
Reviewed the judgement exercised on tax
provisioning, including any material changes
to deferred tax asset recognition.
Reviewed the accounting treatment of
taxes relating to renewal of the Abu Dhabi
onshore concession.
Reviewed the estimated impact of tax
reforms arising from the US Tax Cuts and
Jobs Act.
As a result of changes in the fiscal terms of
the Abu Dhabi onshore concession following
its renewal, the group’s taxes payable
relating to the concession are now principally
reported as income taxes rather than as
production taxes.
Changes to the US corporate tax system
resulted in a one-off deferred tax charge of
$0.9 billion in the fourth quarter 2017 arising
from a revaluation of BP’s US deferred tax
assets and liabilities.
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External audit
Audit risk
The external auditor set out its audit strategy for 2017, 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 in the trading function and
its potential impact on revenue.
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; in addition it reviews the
non-audit services that the auditor provides to the group on a quarterly
basis.
Fees paid to the external auditor for the year were $47 million (2016
$47 million), of which 6% was for non-audit assurance work (see
Financial statements – Note 34). 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 $3 million (2016 $2 million). The
$1 million increase in non-audit fees primarily relates to non-audit related
assurance services, offset by a reduction in tax compliance services.
Non-audit or non-audit related services consisted of other assurance
services. There were no new services contracted for tax compliance
and advisory services for 2017.
Audit effectiveness
The effectiveness, performance and integrity of the external audit
process was evaluated through separate surveys for 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 survey sent to management comprised questions across five main
criteria to measure the auditors’ performance:
• Robustness of the audit process.
• Independence and objectivity.
• Quality of delivery.
• Quality of people and service.
• Value added advice.
Further questions were included on BP’s attitude to the audit and the
progress of the audit transition.
The 2017 evaluation concluded that the external auditor’s performance
had remained largely constant in key areas compared with the previous
year. Areas with high scores and favourable comments included quality
of accounting and auditing judgement, the working relationship with
management and the insight brought through EY’s audit work. Areas
of focus included the need for innovation in the audit and consistency
of audit practices in locations further away from the UK and US. A
further focus was BP’s assessment of its own performance in relation
to the audit.
Results of the annual assessment were discussed with the external
auditor who considered these themes for the 2017 audit service
approach.
A key area of focus from 2016 related to audit team turnover, particularly
for junior members of the teams. Actions taken over the year resulted in
an improvement in the related score for continuity and retention of key
members of the audit team in 2017.
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.
Audit transition
Deloitte was appointed for the statutory audit, with effect from 2018
following a tender process in 2016. The committee monitored the
transition of BP’s statutory auditor from EY to Deloitte, including activity
to enable Deloitte to achieve independence by October 2017. This
included:
• Receiving reports from the audit transition team, including an overview
of operational activities and the termination of non-audit services being
provided by Deloitte to BP – which would be prohibited when Deloitte
becomes the group’s statutory auditor. This included Deloitte stepping
down as independent adviser to BP’s remuneration committee.
• Requiring management to report to the committee on any services
undertaken by the statutory auditor in line with the group’s policies
relating to non-audit services.
• Requiring confirmation of Deloitte’s compliance with BP’s
independence and ethics and compliance rules.
• Inviting Deloitte to attend meetings of the audit committee, joint audit
and SEEA committees and the board from October 2017 as part of its
‘shadowing’ of the audit of the third and fourth quarters 2017.
Deloitte confirmed its independence to the committee in October 2017.
EY resigned on 29 March 2018 following completion of the 2017 audit.
Deloitte will audit the 2018 financial year subject to shareholder approval
at the 2018 AGM.
Changes in Registrant’s Certifying Accountant
Following a competitive tender process and on the audit committee’s
recommendation, in November 2016 the board selected Deloitte as
BP’s independent external auditor for the financial year ending
31 December 2018. This change in external auditor is being made in
accordance with UK and EU law requirements – in particular, the UK
Corporate Governance Code and the reforms of the audit market by the
Competition and Markets Authority and the European Union – which
require that companies put their external audit out to tender at least
every ten years. EY has served as BP’s external auditor since 1909. EY
continued to serve as BP’s external auditor throughout the financial year
ended 31 December 2017.
The audit committee supervised the transition period of Deloitte, as new
external auditor, to ensure the monitoring of Deloitte’s independence
and extended the audit committee’s policy on non-audit services to
Deloitte during the financial year ended 31 December 2017. The board
appointed Deloitte as the company's new external auditor with effect
from 29 March 2018 to fill the vacancy arising from EY’s resignation
following completion of their audit of BP’s 2017 financial statements. At
the 2018 AGM, EY will not stand for re-election and the board will seek
shareholder approval for the appointment of Deloitte as the company's
external auditor until the conclusion of the next AGM at which the
company's accounts are laid before shareholders.
In respect of the financial years ended 31 December 2016 and 2017, EY
did not issue any report on the consolidated financial statements of the
BP group that contained an adverse opinion or a disclaimer of opinion,
nor were the auditor’s report qualified or modified as to uncertainty,
audit scope or accounting principles. There has not been any
disagreement as defined in Item 16F(a)(1)(iv) of Form 20-F with EY over
any matter of accounting principle or practice, financial statement
disclosure, or auditing scope or procedure, which disagreement, if not
resolved to EY’s satisfaction, would have caused EY to make reference
to the subject matter of the disagreement in connection with its
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auditor’s reports, or any reportable event as defined in Item 16F(a)(1)(v)
of Form 20-F.
BP has provided EY with a copy of the foregoing disclosure and has
requested that they furnish BP with a letter addressed to the US
Securities and Exchange Commission (SEC) stating whether or not they
agree with such disclosure and, if not, stating the respects in which they
do not agree. A copy of EY’s letter dated 29 March 2018, in which they
stated that they agree with such disclosure, is filed as Exhibit 15.6.
During the financial years ended 31 December 2016 and 2017 BP did not
consult with Deloitte regarding: (i) the application of accounting
principles to any specified transaction, either completed or proposed,
or the type of audit opinion that might be rendered on the consolidated
financial statements of the BP group; or (ii) any matter that was either
the subject of a disagreement as defined in Item 16F(a)(1)(iv) of Form
20-F or reportable event as defined in Item 16F(a)(1)(v) of Form 20-F.
Auditor 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 prohibition of non-audit tax
services and the limitation of 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 276. The committee’s policies were updated in 2017 to
reflect the revised regulatory guidelines of the FRC, including:
• Adoption of the FRC’s prohibited non-audit services list.
• Prohibition of non-audit tax services by the audit firm.
• Reduction of the pre-approval requirements for non-audit services
in line with FRC guidance on ‘non-trivial’ engagements with the audit
firm.
Committee evaluation
The audit committee undertakes an annual evaluation of its performance
and effectiveness.
2017 evaluation
For 2017 an internal questionnaire was used to evaluate the work of the
committee. The review concluded that it had performed effectively.
Areas of focus for 2018 include succession planning for membership
of the committee and a further review of capital spending.
Actions from the 2016 evaluation
Priorities arising from the 2016 evaluation included a review of and visit
to one of BP’s global business service (GBS) centres, a focus on
streamlining committee materials and further scrutiny on risk
management when undertaking business or functional reviews. The
committee visited GBS in Budapest in 2017, undertaking a review of
the organization’s activities and strategy. It also focused on improving
committee pre-read materials, which received improved evaluation
scores for the 2017 review. And an overview of risk management and
controls was included in all segment and functional reviews.
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BP Annual Report and Form 20-F 2017
83
Role of the committee
The role of the SEEAC is to look at the processes adopted by BP’s
executive management to identify and mitigate significant non-financial
risk. This includes 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
Melody Meyer
John Sawers
Member since September
2014 and chair since May 2016
Member since February 2010
Member since November 2010
Member since June 2007;
retired May 2017
Member since February 2012
Member since May 2017
Member since July 2015
Meetings and attendance
There were six committee meetings in 2017. All directors attended
every meeting for which they were eligible, apart from Cynthia Carroll
who missed one meeting due to a conflicting 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. The group chief executive was invited to join the private
meetings on an ad hoc basis.
Safety, ethics and environment
assurance committee (SEEAC)
On site visits we look for
ourselves and ask questions,
and then we engage with
management.
Chairman’s introduction
The committee continued its work with executive management to
drive safe, ethical and reliable operations. It has reviewed the company’s
management of the highest priority non-financial group risks and
continues to provide constructive challenge to the risk management
process. The risks under their remit remained the same as for 2016:
marine, wells, pipelines, explosion or release at facilities and major
security incidents and cyber security in process control network. The
committee receives reports on each of these risks and monitors their
management and mitigation.
Following publication of the company’s Modern Slavery Act (MSA)
statement in 2017, the committee reviewed related work practices
in BP and will continue to review progress in developing
and embedding those practices. In 2017 it also reviewed the
BP Sustainability Report 2017 and will review the annual update
MSA statement to be published in 2018.
The committee made two site visits in the year (see page 75). In
June, members of the committee visited the Cherry Point refinery in
Washington, and in July members were among the first to visit the
newly operating Glen Lyon floating production, storage and offloading
vessel in the UK North Sea. Our level of access into the operational side
is extensive and gives the committee unique insight. On site visits, we
look for ourselves and ask questions, and then we engage with
management on what this means for the objectives we set. The
committee also continued its schedule of regular meetings with
executive management.
In May, Cynthia Carroll retired from the board and the committee
and in the same month Melody Meyer joined the committee.
Melody brings with her valuable insight through many years of
industry experience, and within a few weeks of joining, participated
in her first committee site visit.
Alan Boeckmann
Committee chair
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Activities during the year
System of internal control and risk management
In addition, the group ethics and
compliance officer and the group
auditor 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
relating to:
• Marine
• Wells
• Pipelines
• Explosion or release
at our facilities
• Major security incidents
• Cyber security (process
control networks).
The committee reviewed these
risks and their management and
mitigation in depth with relevant
executive management.
committee’s visit was the first
formal visit following its start-up.
During visits committee members
and other directors received
briefings on operations, the status
of conformance with BP’s
operating management system ,
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 75 for further details.
The review of operational risk and
performance forms a large part of
the committee’s agenda.
Group audit provided quarterly
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 system of internal
control and risk management
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,
as well as quarterly reports from
group audit.
Site visits
In June members of the
committee, and other directors,
visited the Cherry Point refinery in
Blaine, Washington. The site visit
included a tour of the dock,
training simulator and control
room. Meetings with senior
leadership and representatives
from across the site, including a
local safety committee, were held.
In July committee members, and
other directors, visited the newly
operational floating production,
storage and offloading vessel,
Glen Lyon, at our Quad 204 project
in the UK North Sea. This was one
of the seven major projects
delivered during 2017 and the
Corporate reporting
The committee is responsible
for the overview of the BP
Sustainability Report 2017.
The committee reviewed content
and the revised presentation, and
worked with the external auditor
with respect to their assurance of
the report.
Committee evaluation
For its 2017 evaluation, the committee examined its performance
and effectiveness through an internal questionnaire. 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 members emphasized that site visits remained an important
element of the committee’s work, particularly because they gave
members the opportunity to examine how risk management is being
embedded in businesses and facilities, including in the management
culture.
Joint meetings between the SEEAC 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).
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Joint meetings of the audit and safety, ethics and
environment assurance committees
The audit committee and SEEAC hold joint meetings on a quarterly
basis to simplify reporting of key issues that are within the remit of
both committees and to make more effective use of the
committees’ time. Each committee retains full discretion to require
a full presentation and discussion on any joint meeting topic at their
respective meeting if deemed appropriate.
The committees jointly met four times in 2017, with the
chairmanship of the meetings alternating between the chairman of
the audit committee and chairman of the SEEAC.
Topics discussed at the joint meetings were the quarterly ethics
and compliance reports (including significant investigations and
allegations) and the 2018 forward programmes for the group audit
and ethics and compliance functions. The committees reviewed
the approach and disclosure statement under the UK Modern
Slavery Act and the results of an externally facilitated review
of the effectiveness and performance of group audit.
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BP Annual Report and Form 20-F 2017
See Glossary
85
Remuneration committee
After extensive shareholder
engagement, we were pleased to
receive strong support for our new
remuneration policy at the 2017 AGM.
Chair’s introduction
I am pleased to report on the work of the committee in 2017. Following
substantial engagement with our shareholders in 2016 and early 2017,
we were pleased to receive their support at the 2017 AGM. We applied
our new remuneration policy from the start of 2017 and during the year
have been addressing some transitional arrangements from old to the
new policies. We also reviewed BP pay below the executive team by
region, job level and sector to give additional context to our decisions on
executive pay.
Having served on this committee for six years, and as chair for the last
three, I am stepping down from the committee after the 2018 AGM.
Paula Reynolds, who joined the committee in September 2017, will take
the chair. She is currently chair of the remuneration committee at BAE
Systems plc and has served on that committee since 2015.
During the year, Deloitte LLP had to stand down as our independent
adviser following their forthcoming appointment as auditor. Following a
competitive tender process, we appointed PwC LLP in their place.
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 to 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 remuneration policy for the chairman and the
executive directors.
• Review and determine the terms of engagement, remuneration
and termination of employment for the chairman and the executive
directors as appropriate and in accordance with the policy, and be
responsible for compliance with all remuneration issues applicable
to them.
• Prepare the annual remuneration report to shareholders to show how
the policy has been implemented.
• Approve the principles of any equity plan that requires shareholder
approval.
• Approve the terms of the remuneration of the executive team
(including pension and termination arrangements) as proposed
by the group chief executive.
• Approve changes to the design of remuneration, for BP group leaders
as proposed by the group chief executive.
• Monitor implementation of remuneration for group leaders to ensure
alignment and proportionality.
• Engage independent consultants or other advisers as the committee
may from time to time deem necessary, at the expense of the
company.
Members
Ann Dowling
Member since July 2012 and
chair since May 2015
Alan Boeckmann
Member since May 2015
Ian Davis
Brendan Nelson
Paula Reynolds
Andrew Shilston
Member since July 2010
Member since May 2017
Member since September 2017
Member since May 2015;
retired from the committee
May 2017
Meetings and attendance
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,
the executive team and more broadly on remuneration across the wider
employee population. Both the group chief executive and chief financial
officer are consulted on matters relating to the group’s performance.
The group human resources director 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.
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The committee met eight times during the year. All directors attended
each meeting that they were eligible to attend, either in person or by
telephone, except that Alan Boeckman was not able to attend a
telephone meeting on 27 February in 2017.
Activities during the year
In the period before the 2017 AGM, the committee focused on finalizing
the proposed new remuneration policy and outcomes for 2016. This
involved reviewing directors’ salaries and the group’s performance
outcome which in turn determined the annual bonus and the
performance share plan.
From the 2017 AGM, the committee focused on implementing the new
policy, in particular looking more broadly at remuneration of employees
below the executive team and the measures that could be used to
reflect the transition to a lower carbon world. It also considered the
implications of the transition from the 2014 to the 2017 policies, in
particular aspects relating to share grants, and reviewed potential
outcomes for 2017 at the end of the year.
Following the appointment of Deloitte as the group’s statutory auditor
from 2018 (subject to shareholder approval) and the need for the firm
to be independent prior to the transition of the audit, the committee
appointed PwC as its independent adviser effective September 2017.
The committee continued to monitor developments in potential
regulation and legislation and held early discussions on the possible
implications for its work. It also considered the company’s disclosure
on the UK gender pay gap.
In each of its meetings, the committee focused on the overall quantum
of executive director remuneration and its alignment to the broader
group of employees in BP. It has sought to reflect the views of
shareholders and the broader societal context in its decisions.
Shareholder engagement
There was substantial engagement with shareholders and proxy voting
agencies ahead of the 2017 AGM, primarily carried out by the chair of
the committee, supported by the chairman and company secretary. The
committee chair tested proposals and sought support for the new policy
put to shareholders at the 2017 AGM. In order to understand evolving
issues – particularly around climate change – engagement continued
throughout the year, primarily with larger shareholders and
representative bodies.
Committee evaluation
We undertook an internally facilitated evaluation to examine the
committee’s performance in 2017. The evaluation concluded that
the committee had worked well and continued to evolve after its
intense work leading up to the 2017 AGM.
Focus areas for 2018 included improving oversight of stakeholders’
views on remuneration and in particular, deepening the committee’s
understanding of remuneration below the executive level. In
addition, we focussed on staying up to date with external
developments and emerging ‘best practice’ and improving
remuneration reporting.
See page 90 for the Directors’ remuneration report.
Geopolitical committee
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Chairman’s introduction
I am pleased to report on the work of the geopolitical committee
in 2017, which continued to develop and evolve during the year. In
addition to our regular meetings, we visited the group’s response
information centre in Sunbury, where we were briefed on the group’s
practices and procedures. During 2017 I also joined discussions of the
international advisory board.
Cynthia Carroll and Andrew Shilston stood down from the board at
the 2017 AGM, and Melody Meyer joined the committee in May.
Other board members joined our meetings from time to time.
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.
– 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 BP’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.
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BP Annual Report and Form 20-F 2017
87
Members
John Sawers
Paul Anderson
Frank Bowman
Ian Davis
Melody Meyer
Cynthia Carroll
Andrew Shilston
Member since September 2015
and chair since April 2016
Member since September 2015
Member since September 2015
Member since September 2016
Member since May 2017
Member from September 2016
to May 2017
Member from September 2015;
retired May 2017
Meetings and attendance
Carl-Henric Svanberg and Bob Dudley attend all committee meetings.
The executive vice president, regions and the vice president,
government and political affairs attend meetings as required.
The committee met three times during the year. All directors attended
each meeting that they were eligible to attend except that Cynthia
Carroll was unable to attend the meeting on 1 February 2017.
Activities during the year
The committee developed and broadened its work over the year.
It discussed BP’s involvement in the key countries where it has
investment or is considering investment in detail. These included
Angola, the US, Russia, Mexico, Brazil, India, Mauritania and Senegal.
It considered broader policy issues such as the US domestic and foreign
policy under the new administration and the political and economic
impact of a low price on producing countries.
We reviewed the geopolitical background to BP’s global investments
and the politics around climate change.
Committee evaluation
The committee reviewed its performance by means of an internally
facilitated questionnaire, and discussed the outcome of that evaluation
at its meeting in January 2018.
The evaluation concluded that the committee was working well and
considering the right issues, but stressed the importance of considering
the geopolitics in a country before an investment is made. The
committee currently meets three times a year and is considering
additional meetings.
The committee and board felt that there should be greater integration
between the work of the board, the committee and the international
advisory board.
Chairman’s and nomination committees
Chairman’s introduction
The chairman’s and the nomination committees were actively involved
in the evolution of the board in 2017. In October, I announced that I
would be standing down as chairman at an appropriate time after the
2018 AGM in May. As a result, the board has started the search for my
successor. This is being carried out by the chairman’s committee led
by Ian Davis, the senior independent director.
The nomination committee continues to focus on board renewal and
diversity.
Carl-Henric Svanberg
Chair of the committees
Chairman’s committee
Role of the committee
To provide a forum for matters to be discussed by 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 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.
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Meetings and attendance
The committee met 10 times in 2017. All directors attended all the
meetings for which they were eligible, except that Cynthia Carroll was
unable to attend the meeting on 1 February, as was Paula Reynolds for
the 19 May 2017 meeting. Nils Andersen did not attend the meetings
where succession was discussed. The chairman did not attend the
meeting on 2 February when the committee, led by Andrew Shilston,
the then senior independent director, carried out an evaluation of the
chairman.
Bob Dudley and Brian Gilvary joined meetings where the chairman’s
succession was discussed. Matters relating to the business of the
nomination committee were also discussed at some meetings.
Activities during the year
• Evaluated the performance of the chairman and the group chief
executive.
• Considered the composition of and the succession plans for the
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
• Determined the process for the search for a new chair and appointed
Carl-Henric Svanberg
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advisers to support the committee.
• Commenced the search for the new chair.
• Discussed the strategy options for the company, including the lower
carbon transition.
Member since September
2009 and chair since January
2010
Alan Boeckmann
Member since April 2016
Ann Dowling
John Sawers
Ian Davis
Andrew Shilston
Member since May 2015
Member since April 2016
Member since August 2010
Member between May 2015;
retired May 2017
Andrew Shilston left the committee when he stood down from the
board in May 2017.
Meetings and attendance
The committee met three times in 2017. During the second half of
the year, matters relating to the appointment of new directors were
considered jointly with the chairman’s committee. All directors attended
each meeting that they were eligible to attend.
Activities during the year
The committee monitored the composition and skills of the board.
Paul Anderson will be retiring from the board at the 2018 AGM. The
committee focused on ensuring that the board’s composition is strong
and diverse. As a result, the board is proposing Dame Alison Carnwath
for election as a director at the 2018 AGM.
Committee evaluation
The committee generally continues to work well. Its balance of skills
and experience needs to be maintained so that it is able to govern the
company as it implements its strategy in the transition to the lower
carbon world. It expressed a need to ensure that the board maintains
strong former executive membership and this will be a focus in
forthcoming appointments.
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BP Annual Report and Form 20-F 2017
89
Directors’ remuneration report
We have made our decisions
in a considered way, applying
discretion where necessary, as
we transition to the new policy.
Professor Dame Ann Dowling
Chair of the remuneration committee
Contents
93 Summary of pay and
performance
94 Summary of policy
approach
95 Single figure table
96 Alignment with
strategy
98 Pay and performance
for 2017
102 Implementation of
policy for 2018
105 Stewardship
107 Non-executive
directors
108 Executive directors’
interests
110 Policy summary
tables
Dear shareholder,
Last year, we introduced a new remuneration policy. This
followed extensive consultation with major shareholders
and with their representative bodies. They were clear
that they wanted our policy to be simple and transparent,
with a strong link between pay and performance, and
deliver reduced levels of reward. We listened and
responded to those concerns. We were pleased to
receive strong support for this policy at the 2017 AGM.
It is clear to us that you, our shareholders, expect us to
implement this policy in a considered way and to be
ready to apply discretion when necessary.
2017 has been a transitional year as we have moved from
the old policy to the new. We applied the new policy from
the start of 2017 (see panel opposite). Therefore salary, the
2017 annual bonus and long-term awards made in 2017,
based on performance over the three-year period 2017-19,
are all made under the new policy. However, the long-term
awards granted under the 2015-17 plan were under our old
policy and are based on measures in that policy. The
committee scored the safety, operational and financial
performance against targets set in 2015, before reviewing
the result to see if discretion should be applied. Business
performance over the period, and in particular for 2017, has
been strong, reflected in the company’s first place ranking
for TSR among our peer group of major oil and gas
companies. However, while returns, which have been
explicitly included in the new policy through a ROACE
measure have more than doubled over the last two years,
there is room for further improvement and the company
has continued to incur costs from the Gulf of Mexico oil
spill payments. Taking these factors into account, the
committee chose to reduce the level of payment for these
long-term performance shares by 26%. In applying this
reduction, the committee acted in accordance with the
messages we received from shareholders and the
principles that govern our new policy.
In 2015 Bob Dudley received a maximum performance
award of 550% of salary for the period 2015-17. In the
spirit of applying the new policy early, he requested a
reduction in his maximum award to 500% in line with
the 2017 policy. The committee appreciates this request
which, together with the committee’s discretion, has
reduced his payment by $4.2 million (24%) from the
formulaic outcome.
We believe that the outcome for executive directors,
representing an increase on 2016 but moderated by
discretion, fairly reflects management’s performance and
the experience of shareholders over this longer period,
and is consistent with the aims of the policy approved by
shareholders last year.
Business performance
2017 has been one of the strongest years of operational
delivery for BP. This has been reflected in our financial
results, with a doubling of our underlying replacement
Key outcomes for 2017 Bob Dudley (GCE) – total pay
Seven major
projects delivered
in the year.
First among
peers for total
shareholder
return.
$19.4m
$17.6m
-$3.4m
$11.9m
-$0.8m
$13.4m
Discretion used to
reduce outcome
for performance.
Total pay reduced
by $4.2 million (24%)
due to GCE request
and committee
discretion.
2015
2016
2017
Formulaic
outcome
Impact of
committee
discretion
GCE request
for 2017
policy vesting
(550% to 500%)
2017
single
figure
outcome
More information
Key performance indicators
For an overview of the group’s
KPIs, with those featuring in
the current and previous
remuneration policies, see
page 18.
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cost profit over the year to $6.2 billion and an underlying operating cash
flow of $24.1 billion, excluding post-tax oil spill related payments. Over
the year BP distributed $7.9 billion in dividends. Following consistent
strong progress and the board’s confidence in the growing organic free
cash flow, we recommenced a share buyback programme in the fourth
quarter to offset dilution from the scrip dividend paid to shareholders
electing to receive shares rather than cash.
Our TSR for the period 2015-17 was first among our peer group of major
oil and gas companies. TSR on the UK shares has been 44% over the
three-year period, significantly out-performing the UK market. Seventeen
major projects have been delivered over the three-year period. This has
contributed to a 10% increase in BP’s reported production since 2016
and places us in a strong position for further growth. We have had our
most successful year of exploration since 2004. The downstream
business had an excellent year in terms of replacement cost profit, driven
by strong earnings growth in our marketing and manufacturing
businesses. Our Alternative Energy business grew and BP re-entered
solar but in a new way, partnering with Lightsource to combine our scale,
relationships and expertise in major projects with Lightsource’s expertise
in developing solar projects.
Overall this has been a year of disciplined execution and growth across
the business and BP has made a good start in delivering the company’s
five-year strategy out to 2021.
Committee process for 2017
In order to gain a comprehensive perspective on performance, the
remuneration committee sought the views of the board, audit committee
and safety, ethics and environment assurance committee (SEEAC) to
evaluate the group’s performance against financial, operational and
strategic measures for the purposes of executive remuneration.
Incentive outcomes in 2017
2017 was a year of strong performance and achievements, where all
targets were met or exceeded for the annual bonus, leading to a
formulaic result of 1.54 out of 2. The audit committee and the SEEAC
recommended an exercise of downward discretion. This resulted in the
remuneration committee reducing the final bonus score to 1.43 out of 2.
This results in a bonus of 71.5% of the maximum, half of which will be
delivered as shares and held for three years.
For the performance share award made in 2015, the measures are
relative TSR, and various financial, safety and operational measures
assessed over the three years from 2015 to 2017. The formulaic results
led to an outcome of 96% of maximum, reflecting the fact that BP came
in first place against the peer group on relative TSR and performed
strongly against the other targets set.
This outcome was considered by the committee and reviewed with the
executive directors in the context of the overall levels of pay, the wider
performance of the company, and the experience of shareholders over
How did we determine 2017 outcomes?
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A summary of the 2017 policy is set out on page 110, including
the following changes to the 2014 policy:
Simplification
• Reduction to two incentive plans – a short-term annual bonus and a
long-term performance share plan – deferred shares no longer
matched with additional shares.
• Maximum bonus only earned where stretch performance is
delivered on every measure.
• Fewer measures. Eliminated duplication of measures between
bonus and long-term incentives.
Transparency
• Total shareholder return (TSR) and return on average capital
employed (ROACE) targets disclosed at the start of the three-year
performance period. For awards granted in 2017 and 2018, these
determine 80% of the available performance shares.
• The group’s quarterly results announcements now include updates
on all of the KPIs on which remuneration is based other than TSR,
with commentary on progress on our strategic priorities which, for
awards granted in 2017 and 2018, determine 20% of the available
performance shares.
Reduced package
• The level of bonus paid for an ‘on-target’ score reduced by 25%,
and the mandatory bonus deferral increased to 50% of bonus with
no matching shares. Bonus scale for executive directors now
aligned with the wider managerial population.
• The maximum longer-term incentives for the group chief executive
(GCE) reduced from seven times salary (previously made up of
matching shares on the deferred annual bonus and performance
shares) to a maximum of five times salary.
Link to strategy and shareholder outcome
• Straightforward use of TSR and ROACE as measures of longer-
term performance.
• Performance shares vest based in part on strategic priorities which
include BP’s progress towards a lower carbon future.
Stewardship
• No change to the six-year period for performance shares (three-year
holding period after three-year performance period), nor to the
minimum shareholding requirement of 5x base salary. There is a
new post-retirement holding expectation of 2.5x base salary.
• Safety and the environment remain important considerations
through bonus measures and the underpin on long-term incentives.
• Remuneration committee has the responsibility of balancing the
outcomes from quantitative results with discretion to adjust final
results based on the broader environment and performance.
For the full policy see bp.com/remuneration
1
Assess
performance
2
3
4
Review outcomes
with committees
Alignment with
employees
Apply discretion
Performance assessed against
safety, operational and financial
measures.
Sought input from the SEEAC
and audit committee to ensure a
holistic review of performance.
Determined outcomes
against targets set.
Annual bonus scores reduced
following the committees’ review.
The remuneration committee
considered outcomes in the
context of BP’s group leaders and
the broader comparator group
of US and UK employees in
professional and managerial roles.
The committee used judgement
to reflect the broader market
environment and outcomes for
shareholders.
Downward discretion exercised
for final outcomes.
BP Annual Report and Form 20-F 2017
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Directors’ remuneration report
the three-year period of the plan. In addition, the committee decided to
incorporate early application of some of the principles of the new 2017
policy, for example the more stringent vesting scales. In light of these
factors and an overall assessment of pay relative to performance, the
committee applied its discretion to reduce the 2015 performance share
award vesting from 96% to 70% of maximum.
We also introduced an underpin for performance shares which includes
absolute TSR, safety performance and consideration of issues around
carbon and climate change. This framework will allow the committee to
monitor progress against the broader approach we outlined in February
2018 – reducing our emissions, improving our products and creating low
carbon businesses. See ‘Advancing the energy transition’ on page 96.
The exercise of committee discretion on annual bonus and performance
share outcomes reduced the amount of variable pay by $3.4 million for
Bob Dudley and £1.2 million for Brian Gilvary.
Consistent with the approach of applying certain aspects of the new
policy early, Bob Dudley has requested that his performance share
vesting should be based on an award level of 500% of salary (from the
2017 policy), rather than the 550% of salary that applied for the 2014
policy.
Furthermore, demonstrating their commitment to delivering long-term
sustainable value for BP shareholders, the executive directors have also
voluntarily agreed to the extension of vesting periods for certain share
awards under a discontinued plan as a transitional approach to the new
policy. These share awards remain subject to continued application of a
safety underpin.
Following these decisions, the total reported single figure of pay for
Bob Dudley and Brian Gilvary was $13.4 and £6.5 million. These are
substantially below formulaic outcomes for 2017 but, because the
business performance is much improved, are higher than the single
figure outcomes for 2016. The committee believes that these outcomes
appropriately reflect the strong operational and financial performance of
BP this year and over the past three years whilst demonstrating a
commitment to a considered approach. This year’s single figure for Brian
Gilvary is substantially affected by the inclusion of deferred bonus
shares from 2014 which have now vested, and the 2017 bonus shares
that are being deferred but we now report in the year the shares are
granted.
Implementation of the policy for 2018
We plan to make two changes to the performance measures in 2018.
For the annual bonus, the upstream measure for ‘reliable operations’ will
be changed from ‘upstream operating efficiency’ to ‘BP-operated
upstream plant reliability’, creating comparability between our upstream
and downstream measures. For performance shares granted in 2017,
the ROACE target was based on the final year of the performance
period. In response to investor feedback, we are moving progressively
towards a three-year evaluation period to encourage steady and
sustainable growth. For the 2018 awards, we will average ROACE over
the final two years (2019 and 2020) and then use a three-year average
for 2019 awards onwards.
We reviewed base salaries for the Bob Dudley and Brian Gilvary, noting
the salary increases for UK and US-based employees across the group.
The committee has decided there should be no increase in annual salary
for Bob Dudley. Brian Gilvary’s salary will be increased by 2%, which was
below the general increases for the UK and US based employees across
the group.
Alignment with strategy and the low carbon transition
In 2017 BP announced details of our five-year strategy to 2021, focusing
on strategic and investment choices that are resilient to a range of future
outcomes whilst considering the dual challenge of meeting society’s
need for more energy while working to reduce carbon emissions. To
reinforce the importance of the strategy for the group’s long-term
success, the 2017 policy introduced a balanced but stretching set of
measures into the incentives to reflect BP’s strategy. During the year we
have included updates on our strategic progress in our quarterly results
announcements.
Wider workforce pay
During the year the committee reviewed the group’s approach to
reward below board level across job levels and geographies. This wider
environment provided important context for the committee’s decisions
on executive directors’ remuneration.
Last year, we voluntarily disclosed the GCE-to-employee pay ratio, using
the employee comparator group of the professional/managerial grade
employees based in the UK and US (representing some 30% of the
global employee population). We are aware that regulations will be
introduced to require companies to calculate and disclose a ratio.
As the regulatory methodology is not yet final, we have continued the
practice we adopted in 2017.
Work undertaken by the group in preparation for UK regulatory
requirements on gender pay gap reporting was reviewed with the
committee, who considered the distribution of employees by grade and
gender. In that context the committee received assurance that there
was equal pay for equal or like work.
Committee changes
There have been changes to the membership of the committee during
the year: Andrew Shilston retired from the board at the AGM in May
2017, with Brendan Nelson and Paula Reynolds joining the committee
during 2017. The chairs of both audit committee and SEEAC are now
members of the remuneration committee which strengthens the
committee’s ability to take a wider perspective on the group’s
performance when discussing reward. I believe that we have a broad
range of skills and experience amongst the membership upon which to
draw on when looking at issues around remuneration.
Following six years on this committee, the last three as chair, I have
decided to step down from the committee following the AGM in May
2018. Paula Reynolds will take the chair. I want to take the opportunity to
thank my fellow committee members for their support and welcome
Paula to the role of chair. I would also like to thank the executive directors
for their positive engagement in the policy changes and exercise of
discretion over the last two years.
Conclusion
The board continues to place a high priority on building confidence in
the operation of our remuneration policy. This requires the remuneration
committee to exercise discretion to align pay outcomes to performance,
particularly as we navigate the transition from the pre-2017 policy to our
new policy for the future. We have sought to do this in a considered way
that reflects shareholder expectations, the performance of BP, and the
commitments made to executives. In putting this report forward for an
advisory vote at the AGM, we seek your support for the balance we
have struck.
Professor Dame Ann Dowling
Chair of the remuneration committee
29 March 2018
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Directors’ remuneration report
Summary of our pay and performance for 2017
2017
Business performance
Key strategic highlights
• Underlying replacement cost profit up 139%.
• Organic cash flows back in balance.
• Seven new major projects delivered.
Performance outcomes
We have made good progress, with strong cash flow and share price growth and the announcement of a
number of major investments, all aimed at contributing to returns over the medium and long term.
1st
Among peers for total
shareholder return for
2015-17.
$24.1bn
Operating cash flow,
excluding Gulf of
Mexico payments.
$7.9bn
Dividends paid,
including scrip.
Annual bonus
77%
Formulaic outcome
(% of maximum)
-5.5%
Committee discretion
to reduce award
71.5%
Final outcome after
committee discretion
(% of maximum)
Performance shares
96%
Formulaic outcome
(% of maximum)
-26%
Committee discretion
to reduce award
70%
Expected outcome after
committee discretiona
(% of maximum)
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Nil
Maximum
Performance measures
(% weighting)
Safety
Tier 1 process safety events (10%)
Recordable injury frequency (10%)
Reliability
Refining availability (15%)
Upstream operating efficiency (15%)
Financial
Operating cash flow (excluding Gulf
of Mexico oil spill payments) (20%)
Underlying replacement cost profit (20%)
Upstream unit production costs (10%)
Nil
Maximum
Performance measures
(% weighting)
Financial
Relative TSR (33.3%)
Cumulative operating cash flow (33.3%)
Strategic imperatives
Reserves replacement ratioa (11.1%)
Major project delivery (11.1%)
Safety and operational risk
– Tier 1 process safety events
– Recordable injury frequency
(11.1%)
a The final outcome for part of this award is based on the company’s relative RRR ranking,
presently forecast to be second 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 2018.
Remuneration outcomes
Bob Dudley, group chief executive
Total remuneration
2017
2016
2015
2014
Brian Gilvary, chief financial officer
Total remuneration
$13.4m
$11.9m
2017
2016
2015
2014
$19.4m
$16.4m
£6.5m
£4.2m
£5.1m
£3.6m
Salary and benefits
Retirement benefits
Annual bonus
Performance shares
Discontinued plans
Reduction in total remuneration
$3.4 million
Reduction due to
committee discretion
$0.8 million
Bob Dudley’s
voluntary performance
share reduction
£1.2 million
Reduction due to
committee discretion
Share ownership
Shareholding is a key means by which the interests of executive directors are aligned with those of shareholders. As at 14 March 2018 both
directors had holdings in BP which significantly exceeded their shareholding requirement. Further details are set out on page 105.
Bob Dudley, group chief executive
Brian Gilvary, chief financial officer
Policy requirement: minimum of five times salary
3,065,694 sharesb
10.71 times salary
1,825,299 shares
11.17 times salary
bHeld as ADSs.
BP Annual Report and Form 20-F 2017
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Directors’ remuneration report
Summary of our remuneration policy and approach for 2018
2018
BP’s policy approach
Simplification.
Reduced package
versus previous policy.
Link to strategy.
Stewardship.
Elements of package
Salary and benefits
Retirement benefits
Competitive salary and benefits to reflect role
and home country norms
Annual bonus
Bonus aligned with annual objectives
Performance shares
Share award for meeting three-year targets
Share ownership
Long-term shareholding
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
• The increase to Brian Gilvary’s salary continues to reflect the
$1,854,000 for 2018. Bob Dudley has not received a salary
increase since July 2014.
• With effect from the AGM, the salary for the chief financial officer
will be £775,000.
changes to his role when he took on additional responsibilities
for BP’s trading and shipping functions. This increase of 2% is
within the range used by the company for other UK and US
employees.
• Benefits will remain unchanged – these include car-related
benefits, security assistance, insurance and medical benefits.
Retirement benefits
• From September 2016, Bob Dudley has no further service
• Brian Gilvary receives a cash supplement on the same
accrual under the defined benefit pension arrangements. The
401(k) benefits have been partially capped for future years.
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
• The measures for the bonus are set annually to reflect
every measure.
annual priorities.
• Bonus payable for delivery of bonus scorecard of 1.0 out
• For 2018, performance judged on three key areas:
of 2.0 is half of maximum.
• 50% of any bonus earned will be paid in cash; there will be a
mandatory deferral of 50% into shares for three years.
• Awards will be subject to clawback and malus provisions.
– safety (20%)
– reliable operations (30%)
– financial performance (50%).
• Overall discretion to review outcomes in the context of annual
performance.
Performance shares
GCE – 500%
CFO – 450%
of salary
Directly linked to long-term performance and represents the largest part of the package.
• Three-year performance period, with further three-year
holding period.
• Measures aligned to long-term strategy and shareholders’
interests.
• For 2018 awards, performance judged on three key areas:
– TSR relative to oil and gas majors over three years (50%)
– ROACE based on the average of performance over 2019
and 2020 (30%)
– strategic progress assessed over the performance
• Awards will be subject to clawback and malus provisions.
period (20%).
• Additional underpin – broader performance including
absolute TSR performance and safety and environmental
factors (including consideration of issues around carbon
and climate change) to be considered before determining
vesting outcomes.
Share ownership
Share ownership
Stewardship and alignment with shareholders
• Continuing requirement for directors to maintain a holding
of five times salary.
• It is expected that Bob Dudley and Brian Gilvary will maintain a
holding of at least 250% of salary for two years following
retirement.
• In addition the executive directors have voluntarily agreed
to extend the vesting periods of certain discontinued share
awards, subject to a continued safety underpin.
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Directors’ remuneration report
Single figure table – executive directors’ (audited)
Remuneration is reported in the currency
in which the individual is paid
Bob Dudley
(thousand)
Brian Gilvary
(thousand)
2017
2016
2017
2016
Salary and benefits
Salary
Benefits
Retirement benefits
$1,854
$73
$1,854
$74
Pension and retirement savings – value increasea
Cash in lieu of future accrual
$746
–
$2,205
–
£752
£38
£186
£263
£611
£611
£732
£67
–
£256
£669
–
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$1,491
$1,491
$1,696
–
$7,787b
$13,443
$4,024c
$9,852
£2,981b
£1,455c
£5,440
£3,179
Annual bonus
Cash bonus
Shares – deferred for three years
Performance shares
Performance shares
Total remuneration (excluding discontinued plans)d
Discontinued plans
Deferred share awards from prior-year bonusese
–f
$2,052
£1,040
£1,065
£4,244
Total remunerationd
a 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 and investment gains on
the accumulating unfunded BP Excess Compensation (Savings) Plan (ECSP) account under Bob Dudley’s US retirement savings arrangements. Full details are set out on page 101.
$13,443
$11,904
£6,481
b Represents the assumed vesting of shares in 2018 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 2017 which
was £5.01 for ordinary shares and $39.85 for ADSs. The final vesting will be confirmed by the committee in second quarter of 2018 and provided in the 2018 directors’ remuneration report. Bob
Dudley has requested that the EDIP performance share vesting in respect of the performance period 2015-17 is based on the 500% maximum annual award level which applies under the 2017
directors’ remuneration policy, rather than the 550% maximum annual award level which applies under the 2014 directors’ remuneration policy.
c In accordance with UK regulations, in the 2016 single figure table, the performance outcome value was based on an estimated vesting at an assumed share price of £4.73 for ordinary shares
and $35.39 for ADSs. In May 2017, after the external data became available, the committee reviewed the relative reserves replacement ratio position. This resulted in no adjustment to the final
vesting of 40%. On 19 May 2017, 108,923 ADSs for Bob Dudley and 308,286 shares for Dr Brian Gilvary vested at prices of $36.94 and £4.72 respectively. This total includes the additional
accrual of notional dividends which vested on 2 August 2017. The 2016 values for the total vesting have increased by $310,709 for Bob Dudley and by £67,820 for Dr Brian Gilvary.
d Due to rounding, the total does not agree exactly with the sum of its component parts.
e Value of vested deferred bonus and matching shares. The amounts reported for 2017 relate to the 2014 annual bonus deferred over three years, which vested on 20 February 2018 at the market
price of £4.75 for ordinary shares and include reinvested dividends on shares vested. There was an additional accrual of notional dividends on 29 March 2018 which will vest in 2018 and will be
provided in the 2018 directors’ remuneration report. The amounts reported for 2016 relate to the 2013 annual bonus and have been adjusted from the number provided in the 2016 directors’
remuneration report to include the accrual and vesting of notional dividends.
f As stated in the 2016 directors' remuneration report, 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.
Key outcomes for 2017 Bob Dudley (GCE) – total pay
Seven major
projects delivered
in the year.
First among
peers for total
shareholder
return.
$19.4m
$17.6m
-$3.4m
$11.9m
-$0.8m
$13.4m
Discretion used to
reduce outcome
for performance.
Total pay reduced
by $4.2 million (24%)
due to GCE request
and committee
discretion.
2015
2016
2017
Formulaic
outcome
Impact of
committee
discretion
GCE request
for 2017
policy vesting
(550% to 500%)
2017
single
figure
outcome
BP Annual Report and Form 20-F 2017
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Alignment with strategy
BP set out an update of its strategy in 2017, which was reinforced in the results announcement in February 2018. The foundations for strong
performance are safe and reliable operations, a balanced portfolio, and a focus on returns.
How we align
our strategy and
remuneration
measures
Safer
Fit for
future
Focused on
returns
Safe, reliable
and efficient
execution
A distinctive
portfolio fit for a
changing world
Value based,
disciplined
investment and
cost focus
Growing sustainable
free cash flow
and distributions to
shareholders over the
long term
Element of remuneration
Annual bonus
Safety
Reliable operations
Financial performance
Performance shares
Total shareholder return
Return on average capital
employed
Strategic priorities
Underpin: absolute TSR
and safety/environmental
factors
Low carbon transition
BP’s ambition is to provide more energy while advancing the energy
transition. The focus on lower carbon has three main elements:
Reducing our
emissions in
our operations
Improving
our
products
Creating
low carbon
businesses
Reducing our
emissions through
operational emission
reduction activities.
Improving our
products to enable
customers to lower
their emissions.
Creating low
carbon businesses
to grow value and
complement our
existing portfolio.
Strategic priorities
The strategic priorities component of the performance shares
covers measurement across a range of objectives including: growing
gas and advantaged oil in the upstream; market-led growth in the
downstream; venturing and low carbon across multiple fronts;
and gas, power and renewables trading growth. These priorities
are aimed at growing sustainable value for our shareholders and
increasing the proportion of lower carbon activities in our portfolio
over time. The seven major project start-ups in 2017 (see page 14)
have enabled a significant shift in the proportion of gas in our
portfolio, laying a strong foundation for our gas business moving
forwards.
Progress against each of the strategic priorities is being monitored
against a balanced set of measures that will be viewed in the
round relative to strategy. For example, ‘growing gas and
advantaged oil in the upstream’ will be assessed against a range
of measures including the proportion of gas in the portfolio
and the movement of unit production costs per barrel (which
reflect how ‘advantaged’ the barrels are).
More information
Advancing the energy transition
In this report, we examine how the
energy world is rapidly changing, set
out our low carbon ambitions and the
changes we are making across our
entire business to help advance the
energy transition. Publishes April,
see bp.com/energytransition
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The committee believes that BP’s strategic priorities can help
advance the energy transition. The measures related to our lower
carbon activities – gas, venturing, renewables trading and renewable
energy – underscore this commitment. These activities should grow
over time.
Our performance share plan features an underpin which will be
applied after the formulaic outcome but before the final vesting
outcome has been determined. This underpin takes into account
absolute TSR, safety and environmental factors (including
consideration of issues around carbon and climate change). In this
regard, the committee will consider progress on matters such as
reducing emissions, improving our products and creating low carbon
businesses.
GCE-to-employee pay ratio
The committee commenced reporting on the GCE-to-employee pay ratio
in 2017. The committee notes that regulations will be published during
2018, setting out a methodology for the calculation of such a ratio. As
the regulatory methodology to be used is not yet final, the committee
has continued with the approach we used in 2017 and the comparator
group which it believes is the most relevant for BP.
This group is the professional/managerial grade employees based in the
UK and US which represent some 30% of the global employee
population and is used elsewhere in this report. The GCE-to-median
worker pay ratio for this group was 92 to 1 in 2017 (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.
Remuneration in the wider group
During the year the committee has received detailed information
on pay below the board by region and job level, including the cascade
of pay mix and incentive structures, typical salary budgets, and
approaches across different sectors of the group’s business. This
context has informed decision making on executive director pay, for
example in relation to bonus outcomes, which are largely aligned
across the group, and salary increases.
UK gender pay gap
The committee reviewed the data and methodology for the group’s
reporting against the UK gender pay gap regulations. These require
the company to publish the difference in mean and median pay, mean
and median bonus pay, proportion of male and female employees
who received bonus pay and the number of male and female
employees in quartile pay bands.
The committee also looked at factors such as:
• The uneven gender distribution of employees within BP job grades.
• How certain roles with specific pay practices such as allowances
(e.g. offshore/rotator allowances) and bonus structures (e.g. trading
bonuses) have a disproportionally higher number of men and
contribute to the pay and bonus gap.
• How the gender pay gap analysis does not take grades and roles
into consideration (as when analysing by internal grade, BP’s pay
gap falls significantly).
The committee was assured that the group provides equal pay for equal
or like work.
Finally the committee and the board considered BP’s initiatives to
support long-term growth in female talent, including developing the
technical talent pool, hiring, retention and progression. BP’s gender
pay gap in 2017 report was published on 21 February 2018 and can
be found at bp.com/ukgenderpaygap.
Percentage change in GCE remuneration
Comparing 2017 to 2016
% change in GCE remuneration
% change in comparator group
remuneration
Salary
0%
4.3%
Benefits
Bonus
-0.6% 75.8%
0% 22.9%
The comparator group used here is the same as that used in the pay ratio
calculation above, and comprises some 30% 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.
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Relative importance of spend on pay ($ million)
Distributions to
shareholders
Remuneration paid to
all employeesa
Capital investmentb
16,501
16,675
10,204
11,233
7,867
7,469
2017
2016
2017
2016
2017
2016
a Total remuneration reflects the reduction in number of employees and the total overall
employee costs. See Financial statements – Note 33 for further information.
b Capital investment is illustrated to reflect the overall scale of BP investment decisions.
BP changed its reporting of organic capital expenditure to a cash basis in 2017; the 2016
number has been restated to be reported on a cash basis.
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BP Annual Report and Form 20-F 2017
97
Directors’ remuneration report
Pay and performance for 2017
Salary and benefits
Base salary
No salary increase was awarded to Bob Dudley for 2017 and his salary
remained at $1,854,000. Bob Dudley has not received a salary increase
since 2014.
As was disclosed in the 2017 report to shareholders, Brian Gilvary’s
salary was increased with effect from May 2017 to £759,000 reflecting
his additional responsibilities for BP’s trading and shipping functions.
Annual bonus
The targets for the 2017 annual bonus were set at the start of the year
based on a combination of safety, reliability and financial performance.
Targets were set in the context of the group’s strategy and the
annual plan.
During 2017 BP’s share price performed strongly. The group distributed
$7.9 billion to shareholders in cash and scrip dividends. In the fourth
quarter, the group commenced a share buyback programme to mitigate
the dilutive effects of issuing shares under the scrip dividend
programme.
Overall it was one of the strongest years in BP’s recent history. There
was delivery of the group’s strategy, particularly the delivery of seven
major projects within the year and below the total budget. There were
strong earnings in the downstream and a 10% year-on-year increase in
production for the BP group as a whole.
The group’s operating cash flow was strong and well above plan.
Underlying replacement cost profit was $6.2 billion, an increase of
139% on 2016. Goals for reduction in controllable costs were delivered,
together with good discipline on capital expenditure. Operational
reliability was high and safety outcomes were above target.
When reviewing performance over the period, the committee sought
input from the chairs of the audit committee and the SEEAC to ensure
a comprehensive review of performance.
Following input from the audit committee on the treatment of certain
accounting items for which it would not be appropriate for participants to
benefit, for example a gain from a legal settlement, the formulaic score
under the bonus was reduced from 1.54 to 1.49. In addition, the SEEAC
recommended an exercise of downward discretion to the safety
element for executive directors after taking a longer term view of safety
performance to date. Following SEEAC’s recommendation on the safety
component of the scorecard, the remuneration committee exercised its
discretion to reduce the score by 0.06, resulting in a final annual bonus
scorecard outcome of 1.43 out of 2, a payout of 71.5% of maximum.
Benefits
Executive directors received car-related benefits, security assistance,
insurance and medical benefits.
Overall, the committee believes that the bonuses for 2017 fairly reflect
performance over the period.
Outcome
Name
Bob Dudley
Brian Gilvary
Adjusted outcome
after committee
discretion
(thousand)
$2,983a
£1,221a
Paid
in cash
(thousand)
$1,491
£611
Deferred
into BP
shares
(thousand)
$1,491
£611
a Due to rounding, the total does not agree exactly with the sum of its component parts.
Under the terms of the 2017 policy, half of the bonus earned is deferred
into shares that will vest after three years. Deferred bonus shares are
now reported in the single figure for the bonus year to which they relate.
This is different from the 2014 policy, when the shares were only
reported on vesting at the end of the three-year period. For Brian Gilvary,
the 2017 single figure includes both the 2017 bonus deferred to future
years, and the deferred shares from the 2014 bonus vesting in the
current period.
98
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Directors’ remuneration report
Annual bonus – continued
Scorecard
2017 annual bonus
REM Measures used for the 2017 remuneration policy.
1 Safety
0.25
2
Reliable
operations
0.45
3
Financial
performance
0.84
Measures
Weighting
Threshold (0)
Target (1)
Maximum (2)
1
Safety (20% weight)
Tier 1 process safety event
(defined by API)
10%
Recordable injury frequency
10%
Safety outcome
2
Reliable operations (30% weight)
Downstream refining availability
(Solomon Associates’
operational availability)
15%
Upstream operating efficiency
15%
Reliable operations outcome
3
Financial performance (50% weight)
Operating cash flow
(excluding Gulf of Mexico
oil spill payments)
Underlying replacement
cost profit
20%
20%
Upstream unit production costs
10%
Financial performance outcome
4
Formulaic score
24 events
0
20 events
0.1
14 events
0.2
0.249/200k hrs
0
0.228/200k hrs
0.1
0.188/200k hrs
0.2
94.6%
0
77.3%
0
$19.9bn
0
$5.0bn
0
$7.7/bbl
0
95.1%
0.15
79.3%
0.15
$21.4bn
0.2
$5.8bn
0.2
$7.3/bbl
0.1
95.6%
0.3
81.3%
0.3
$22.9bn
0.4
$6.6bn
0.4
$6.9/bbl
0.2
Formulaic
scorecard
outcome
1.54 out of 2
Audit committee
Discretion
- 0.05
SEEAC
Discretion
- 0.06
Final scorecard
outcome
1.43 out of 2
More information
Key performance indicators page 18
4
Formulaic score
1.54 out of 2.0
Performance and
outcome
18 events
0.13
0.218/200k hrs
0.12
0.25
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95.3%
0.21
80.5%
0.24
0.45
$24.1bn
0.4
$6.2bn
0.29
$7.11/bbl
0.15
0.84
1.54 out of 2.0
71.5%
outcome of
maximum
bonus
Performance shares
For performance shares awarded in 2015, vesting was determined
under the terms of the 2014 policy, by a combination of relative TSR,
safety, financial and operational performance assessed over the three
years from 2015 to 2017. The results are summarized in the table on
page 100.
TSR – the company’s TSR over the three-year period was in first place.
The TSR element is measured on a relative basis in common currency
against the oil majors: Chevron, ExxonMobil, Shell and Total.
Cumulative operating cash flow – under the 2014 policy, the
outcome was measured by taking the cumulative operating cash flow
for the three years. This measure was assessed by adjusting the target
to the actual oil price as has been the case in previous years. Against this
adjusted target, this element of the performance shares achieved
maximum score of 33.3%. Without adjustment, the score
would reduce from 33.3% to 32.4%, a reduction of 0.9%.
Safety and operational risk – assessed through a look-back over tier 1
process safety events and recordable injury frequency (RIF) over the
three-year period. The committee sought input from the SEEAC in
making this subjective assessment. The SEEAC noted the reduction in
tier 1 events, the trend in RIF and the high annual scores for both safety
measures throughout the three-year period and recommended a score
of 85% of maximum for this element of the performance shares.
BP Annual Report and Form 20-F 2017
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Directors’ remuneration report
Performance shares – continued
Project delivery – the vesting outcome reflects the strong progress
over the three-year period with 17 projects delivered, seven within 2017.
Further details of these projects are set out on page 14.
Relative reserves replacement ratio – preliminary assessment
indicates vesting for this measure. For the purpose of this report, a
forecast of second place has been used. The final outcome for this
measure will be confirmed later in the year, once competitor data is
published in full.
Contextual review
The committee undertook a wider review of performance over the
three-year performance period, in the context of the overall levels
of pay, the wider performance of the company, and the experience of
shareholders over the three-year period of the plan. While performance
over the period, and in particular in 2017, has been strong, we also
recognize that although returns have doubled over the past year, there is
still room for further improvement and that the company has continued to
Scorecard
2015-17 performance shares
REM
These measures were used under the terms of our previous policy.
incur costs associated with Gulf of Mexico oil spill payments. The
committee also sought where appropriate to apply principles of the
new policy early to awards vesting in respect of 2017 performance. This
included, for example, consideration of the more stringent vesting scales
adopted in the 2017 policy. In light of these factors and an overall
assessment of pay relative to performance, the committee determined
that it would be appropriate to exercise downward discretion on this part of
the award. It also determined that the vesting for the 2017 award should be
reduced from the formulaic outcome of 96% of maximum to 70% of
maximum. In addition, consistent with the approach of applying the
principles of the 2017 policy to awards vesting in the year, Bob Dudley
asked the committee to base his performance shares award on 500% of
salary that applies under the terms of the 2017 policy, rather than the
550% of salary that was actually granted in 2015. The committee’s
discretion and Bob Dudley’s request together reduced his performance
shares by $4.0 million (34%).
More information
More information
Key performance indicators page 18
Key performance indicators page XX
1 Financial
66.6%
Measures
1 Financial
2
Strategic imperatives
29.4%
3
Formulaic vesting
96.0%
Weighting
at maximum
Threshold
performance
Maximum
performance
Performance
and outcome
Relative total shareholder return
Cumulative operating cash flow
33.3%
33.3%
2
Strategic imperatives
Relative reserves replacement ratio
11.1%
Major project delivery
11.1%
Third
$45.6bn
Third
10
First
$61.6bn
First
14
Safety and operational risk:
– Process safety tier 1 events
– Recordable injury frequency
3
Total formulaic vesting
Formulaic
vesting:
96%
11.1%
Continuous improvement look back
Committee review of context and shareholder
experience over three-year period of plan
First
33.3%
$61.9bn
33.3%
66.6%
Second
8.9%
17
11.1%
85% of maximum
9.4%
29.4%
96.0%
70%
final vesting
after committee
discretion
The committee’s discretion and Bob Dudley’s request together reduced the vesting value of his
performance shares by $4.0 million
100
BP Annual Report and Form 20-F 2017
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Directors’ remuneration report
Performance shares – continued
Preliminary outcome – 2015-17 performance shares
Name
Bob Dudley
Brian Gilvary
Shares awarded
1,501,770
685,246
Shares vesting
including dividends
1,172,484
594,932
Value of
vested shares
$7,787,248
£2,980,609
These values are based on estimated vesting levels. As noted above,
final vesting will be determined once competitor data is published in
respect of relative reserves replacement (RRR).
2014-16 performance shares – final outcome
Last year the committee made a preliminary assessment of third place
for the relative RRR in the 2014-16 performance shares element.
In April 2017 the committee reviewed the results for all comparator
companies as published in their annual reports and assessed that
BP was in third place relative to other oil majors and that no further
adjustment was required.
Discontinued plans: deferred bonus and matching shares
Both Bob Dudley and Brian Gilvary deferred two thirds of their 2014
annual bonus in accordance with the prevailing terms of the deferred
bonus plan.
The original three-year performance period for this deferred award
ended on 31 December 2017.
As required by the terms of the discontinued plan, 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 consideration
of the long-term performance trend.
Over the three-year period 2015-17 safety performance continued to
demonstrate progress and improvement overall. 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.
As a sign of their commitment to the long-term interests of the
company, and to further align with the shareholder experience, both
Bob Dudley and Brian Gilvary have requested that the committee delay
Conclusions of the safety and sustainability assessment
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the vesting of some of the awards under discontinued plans. In light of
this request, the committee has approved the deferral of Bob Dudley’s
2014 deferred and matching awards until after his retirement from the
group. The vesting of Brian Gilvary’s 2014 matching award will also be
deferred for a period of two years. The committee will extend the
original safety and environmental sustainability performance condition
for the same period.
Following the committee’s review, full vesting of Brian Gilvary’s
deferred shares in respect of the 2014 deferred bonus was approved.
No further matching awards will be granted under the deferred bonus
plan following approval of the 2017 remuneration policy by shareholders
at the 2017 AGM.
2014 deferred bonus vesting – outcome
Name
Bob Dudleya
Brian Gilvary
Shares
deferred
588,216
353,152
Vesting
agreed
–
100%
Total shares
including
dividends
–
219,004
Total value at
vesting
–
£1,040,269
a 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.
No systemic
issues identified
No major incidents
Safety culture and values
embedded within the
global organization
Strong safety performance
supports efficiency and financial
results across the group
Retirement benefits
2017 outcomes
Bob Dudley participates in the US pension and retirement savings plans
described on page 104. In 2017, Bob Dudley’s accrued defined benefit
pension did not increase. In accordance with the requirements of the UK
regulations, the value attributed to this accrued pension in the single
figure table on page 95 is therefore zero. In relation to the retirement
savings plans, Bob Dudley made contributions in 2017 to the ESP
totalling $27,000. For 2017 the total value of BP matching contributions
in respect of Bob Dudley to the ESP and notional matching contributions
to the ECSP was $129,800, 7% of eligible pay. After adding the
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 95 is $746,200.
Brian Gilvary participates in the UK pension arrangements described
on page 104 in common with over 4,500 UK employees employed prior
to 2010. In 2017 as a result of his salary increase Brian Gilvary’s accrued
pension increased, net of inflation, by £9,280. This increase has been
reflected in the single figure table on page 95 by multiplying it by a factor
of 20 in accordance with the requirements of the UK regulations (giving
£185,600).
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 95.
The committee continues to keep under review the increase in the value
of pension benefits for individual directors and its alignment to the
broader workforce.
• The BP defined benefit (DB) plan remains open for employees in the
UK who were employed before 2010 (or before 2014 in the North Sea).
The plan provides an inflation linked pension of 1/60th of final salary for
each year of service. As of October 2017 over 4,500 active employees
were members of the plan.
• Currently over 800 employees have, like Brian Gilvary, elected to stop
future service accrual under the DB plan and instead receive a cash
allowance of 35% of base pay, reducing to 15% by April 2024. Brian
Gilvary receives the same cash allowance as those 800 other
employees.
BP Annual Report and Form 20-F 2017
101
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Directors’ remuneration report
Implementation of the policy for 2018
Salary and benefits
The committee noted that salary increases for UK and US based
employees across the group were generally around 3%. The committee
has considered the salaries for Bob Dudley and Brian Gilvary and
has decided that there will be no increase for 2018 for Bob Dudley.
Brian Gilvary’s salary will be increased by 2% to £775,000.
Benefits for 2018 will remain broadly unchanged from prior years.
Annual bonus
For 2018, the bonus measures will again focus on three areas: safety
and operational risk, 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 continues to focus on measures that are robust
and externally comparable. In addition, the measures linked to reliable
operations also require execution of good safety practices.
The committee has agreed that the upstream measure for ‘reliable
operations’ be amended from ‘upstream operating efficiency’ to
‘BP-operated upstream plant reliability’. This latter measure is more
comparable with the equivalent metric disclosed for the downstream.
Although the detail of the targets is currently commercially sensitive,
the committee intends to continue to provide retrospective disclosure
following the year end. The targets have been agreed by the committee
after consultation on the safety targets with the SEEAC and on the
financial targets with the audit committee.
Measures for 2018 annual bonus
Salary increases over the last five years
Bob Dudley
Brian Gilvary
2018
Nil
2017
Nil
2016
Nil
2015
Nil
2014
Bob Dudley
Brian Gilvary
3.0%
2018
2017
2016
Nil
2015
Nil
2014
Salary with
effect from AGM
$1,854,000
£775,000
2.0%
3.75%
3.0%
Increase
Nil
2%
One of the challenges faced in a commodity industry is to provide a
fair assessment of underlying performance, and therefore changes in
plan conditions (including oil and gas prices and refining margins) are
considered when reviewing financial outcomes. The committee retains
discretion to review outcomes in the context of overall performance.
Awards will be subject to malus and clawback provisions as described
in the 2017 policy.
The maximum bonus opportunity is 225% of salary for a maximum
bonus score of 2.0. In accordance with the 2017 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) is 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.
Element
1
Safety
20%
Measures
include
Recordable injury
frequency
Weighting
for 2018
10%
Tier 1 process safety events
10%
2
Reliable operations
3
Financial performance
30%
Measures
include
50%
Measures
include
Weighting
for 2018
BP-operated upstream
plant reliability
Downstream refining
availability (Solomon Associates’
operational availability)
15%
15%
Weighting
for 2018
20%
20%
Operating cash flow (excluding
Gulf of Mexico oil spill payments)
Underlying replacement
cost profit
Upstream unit production costs
10%
102
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Directors’ remuneration report
Performance shares
Under the 2017 policy the measures for the performance shares
focus on shareholder value, capital discipline and future growth.
Shareholder value
The TSR element is measured on a relative basis in common currency
against the oil majors: Chevron, ExxonMobil, Shell and Total. The
committee continues to believe that the current comparator group
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
ROACE is calculated by dividing the underlying replacement cost profit
(after adding back net interest) by average capital employed excluding
cash and goodwill (for full definition, see the Glossary on page 289).
ROACE is measured based on the actual price environment for each of
the years in question; there will be no adjustments for changes to plan
conditions.
For the 2017-19 performance shares, this assessment will be based
on the final year of the three-year period. The committee has reviewed
this methodology in the light of engagement with shareholders and
broader FTSE practice and has decided to move progressively to a
determination of ROACE on a three-year average rather than being
based on the final year. For the 2018-20 performance shares, the
Measures for 2018 performance shares
Element
calculation of ROACE will be averaged over the last two years and
for 2019-21 performance shares, the intention is that it will be averaged
over the full three-year period.
Targets for TSR and ROACE measures for 2018 – determining 80%
of the performance shares available – are set out below at the start
of the assessment period.
Future growth
Measures for the strategic element are directly focused on delivery of
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. The
board regularly reviews progress on the strategic priorities throughout
the year and BP’s quarterly results announcement includes updates on
the group’s strategic progress.
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1
Relative TSR versus oil majorsa
2
Return on average capital employedb
3
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
• Growing gas and advantaged oil in
the upstream
100% of element
11.5% 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 the average of performance over 2019 and 2020. 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 and the underpin
Prior to approving vesting outcomes, the committee will additionally
consider the broader performance of the business including absolute
TSR performance, together with safety and environmental factors
(including consideration of issues around carbon and climate change)
over the three-year period as part of an underpin. The underpin will be
applied after the formulaic outcome for the performance shares but
before the final vesting outcome has been determined. In looking at
environmental factors, the committee will consider the group’s progress
on issues such as reducing emissions, improving our products and
creating low carbon businesses.
In line with our new policy, share awards will be made at the level of
500% of salary for Bob Dudley and 450% of salary for 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.
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103
Brian Gilvary
Brian Gilvary participates in a UK final salary pension plan, the BP
Pension Scheme (BPPS), along with over 4,500 other employees in
service prior to 1 April 2011. The BPPS is closed to new hires but for
existing participants the plan continues to provide 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.
BPPS participants can elect to stop future service pension accrual and
instead receive a cash allowance. On 1 April 2011 Brian Gilvary elected
to stop future service pension accrual and receive the cash allowance of
35% of base salary. It has been agreed for all participants who have
elected to receive the cash allowance, including Brian Gilvary, that a
transition will take effect from April 2021 when the level of cash
allowance 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 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, Brian Gilvary has a normal retirement
age of 60.
If 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.
Directors’ remuneration report
Retirement benefits
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 and annual
bonus. 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.
Although investment returns on the ECSP relate to contributions made
in previous years, UK disclosure rules for the single figure require these
returns to be included in the single figure for the year. As Bob Dudley
has a significant proportion of his notional ECSP investment in BP
shares, an increase in the BP share price results in a contribution to
the single figure through this component.
Benefits payable under the ECSP 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 exceed the share ownership requirements of
five times salary. It is expected that Bob Dudley and Brian Gilvary will
maintain a shareholding of at least 250% of salary for two years
following retirement.
104
BP Annual Report and Form 20-F 2017
Book 1.indb 104
03/04/2018 16:44:31
Directors’ remuneration report
Stewardship
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.
As reported last year, 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.
As a sign of their commitment to the long-term interests of the
company, and to further align with the shareholder experience, both
executive directors have requested that the committee delay the vesting
of some of the awards under discontinued plans. Bob Dudley has
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. In a similar way, the vesting of Brian
Gilvary’s 2014 matching award will also be deferred for a period of two
years. As per the original terms, the committee will extend the safety
and environmental sustainability performance condition for the same
period.
These factors significantly extend the time horizons for both executive
directors. 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 14 March 2018 of the directors’ interests shown below
excluding the assumed vesting of the 2015-17 performance shares.
Current directors
Bob Dudley
Brian Gilvary
Appointment date
October 2010
Value of current
shareholding
$19,860,588
January 2012
£8,483,077
% of policy
achieved
214
223
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.
Ordinary
shares or
Ordinary shares
equivalents at
or equivalents
31 Dec 2017
at 1 Jan 2017
2,509,500 3,065,520
1,709,243
1,419,263
Current directors
Bob Dudleya
Brian Gilvary
a Held as ADSs.
Changes from
31 Dec 2017 to
14 Mar 2018
Ordinary shares
or equivalents
total at
14 Mar 2018
174 3,065,694
1,825,299
116,056
C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
n
c
e
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 applicable performance
conditions have been satisfied.
Ordinary
shares or
equivalents at
1 Jan 2017
6,607,314
3,259,891
Ordinary
shares or
equivalents at
31 Dec 2017
6,870,048
3,329,274
Changes from
31 Dec 2017 to
14 Mar 2018
0
(176,576)
Ordinary shares
or equivalents
total at
14 Mar 2018
6,870,048
3,152,698
Current directors
Bob Dudleya
Brian Gilvary
a Held as ADSs.
At 14 March 2018, 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 109.
Current director
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 14 March 2018,
all directors and other members of senior management as a group held
interests of 15,896,179 ordinary shares or their calculated equivalents,
6,757,019 restricted share units (with or without conditions) or their
calculated equivalents, 10,022,746 performance shares or their
calculated equivalents and 5,012,307 options over ordinary shares or
their calculated equivalents under the BP group share option schemes.
Senior management comprises members of the executive team. See
page 66 for further information.
History of CEO remuneration
Year
2009
2010c
2011
2012
2013
2014
2015
2016
2017
Total
remuneration
thousanda
£6,753
£3,890
$8,057
$8,439
$9,609
$15,086
$16,390
$19,376
$11,904
$13,443
Annual bonus
% of
maximum
89b
0
0
67
65
88
73
100
61
71.5
Performance
shares vesting
% of maximum
17.5
0
0
16.7
0
45.5
63.8
74.3
40
70
CEO
Hayward
Hayward
Dudley
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 2017, 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 CEO until October 2010.
Book 1.indb 105
03/04/2018 16:44:31
BP Annual Report and Form 20-F 2017
105
Shareholder engagement
As set out in last year’s report, during 2017 we had extensive dialogue
with many of our largest shareholders as well as representative bodies
on remuneration matters, particularly in the run-up to the AGM.
The table below shows the votes on the report for the last three years.
AGM directors’ remuneration report vote results
Votes withheld
% vote ‘against’
Year
2.95%
2017
63,453,383
59.3% 464,259,340
2016
305,297,190
11.2%
2015
% vote ‘for’
97.05%
40.7%
88.8%
The remuneration policy was approved by shareholders at the 2017
AGM on 17 May 2017. The votes on the policy are shown below.
2017 AGM directors’ remuneration policy vote results
Year
2017
% vote ‘against’
2.72%
% vote ‘for’
97.28%
Votes withheld
36,563,886
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 as non-executive directors during 2017 are
shown below.
Director
Bob Dudley
Brian Gilvary
Appointee
company
Rosnefta
L’Air Liquide
Additional position
held at appointee company
Director
Director
Total fees
0
Euros 64,310
a Bob Dudley holds this appointment as a result of the company’s shareholding in Rosneft.
Directors’ remuneration report
Further information
Historical TSR performance
FTSE 100
BP
£250
£200
£150
£100
£50
l
i
g
n
d
o
h
0
0
1
£
l
a
c
i
t
e
h
t
o
p
y
h
f
o
e
u
a
V
l
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
This graph shows the growth in value of a hypothetical £100 holding in
BP p.l.c. ordinary shares over nine years, relative to a hypothetical £100
holding in the FTSE 100 Index of which the company is a constituent.
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 86.
During 2017 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.
Deloitte LLP acted as independent adviser to the committee during
the year until September 2017, when it stepped down as part of the
transition process for its role as BP’s statutory auditor for the financial
year 2018.
Following a competitive tender process, the committee appointed PwC
as its independent adviser from September 2017. PwC 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.
Freshfields Bruckhaus Deringer LLP provided legal advice on specific
compliance matters to the committee.
Deloitte, PwC and Freshfields provide other advice in their respective
areas to the group. During the year, Deloitte also provided BP with
services including consulting on HR and upstream matters and PwC
provided BP with services including subsidiary company secretarial
support.
Total fees or other charges (based on an hourly rate) for the provision of
remuneration advice to the committee in 2017 (save in respect of legal
advice) are as follows:
Deloitte £164,280
PwC
£62,213
106
BP Annual Report and Form 20-F 2017
Book 1.indb 106
03/04/2018 16:44:31
Directors’ remuneration report
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 2017 AGM. This policy was implemented
during 2017. There has been no variance of the fees or allowances for
the chairman and the NEDs during 2017.
Chairman
The fee structure for the chairman, which has been in place since
1 May 2013, is £785,000 per year. 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.
The table below shows the fees paid for the chairman for the year ended
31 December 2017.
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.
2017 remuneration (audited)
2017 remuneration (audited)
£ thousand
Fees
Benefitsa
Total
£ thousand
Fees
Benefitsa
Total
Carl-Henric Svanberg
2017
785
2016
785
2017
35
2016
58
2017
820
2016
843
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 1,229%.
Ordinary
shares or
equivalents at
1 Jan 2017
Ordinary
shares or
equivalents at
31 Dec 2017
Change from
31 Dec 2017
to
14 Mar 2018
Ordinary
shares or
equivalents
total at
14 Mar 2018
2,076,695
2,076,695
–
2,076,695
Chairman
Carl-Henric
Svanberg
Nils Andersen
Paul Anderson
Alan Boeckmann
Admiral Frank Bowman
Cynthia Carrollb
Ian Davis
Professor Dame Ann
Dowlingc
Melody Meyerd
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Andrew Shilstonb
2017
115
155
165
155
54
154
145
86
138
140
145
75
2016
23
165
168
162
140
136
150
–
130
140
148
190
2017
17
27
11
15
36
2
5
23
14
8
5
1
2016
6
32
17
14
28
2
2
–
30
17
19
5
2017
132
182
176
170
90
156
150
109
152
148
150
76
2016
29
197
185
176
168
138
152
–
160
157
167
195
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 Resigned on 17 May 2017.
c In addition, Professor Dame Ann Dowling received £25,000 for chairing and being a member
of the BP technology advisory council.
d Appointed on 17 May 2017.
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.
C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
n
c
e
Nils Andersen
Paul Anderson
Alan Boeckmann
Admiral Frank Bowman
Cynthia Carrolla
Ian Davis
Professor Dame Ann Dowling
Melody Meyerc
Brendan Nelson
Paula Rosput Reynolds
Sir John Sawers
Andrew Shilstona
a Resigned on 17 May 2017.
b Held as ADSs.
c Appointed on 17 May 2017.
Ordinary shares
or equivalents at
1 Jan 2017
47,855
30,000b
44,772b
24,864b
10,500b
25,735
22,320
–
11,040
52,200b
13,528
15,000
Ordinary shares
or equivalents at
31 Dec 2017
125,000
30,000b
44,772b
24,864b
–
47,500
22,320
20,646b
11,040
58,200b
14,198
–
Change from
31 Dec 2017 to
14 Mar 2018
–
–
–
–
–
–
–
–
–
15,000
–
–
Ordinary shares
or equivalents
total at
14 Mar 2018
125,000
30,000b
44,772b
24,864b
–
47,500
22,320
20,646b
11,040
73,200b
14,198
–
Value of
current
shareholding
£580,938
$194,350
$290,048
$161,077
–
£220,756
£103,732
$133,752
£51,308
$474,214
£65,985
–
% of policy
achieved
645
168
250
139
–
184
115
115
57
409
73
–
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 2017, he received £100,000 for this role.
BP Annual Report and Form 20-F 2017
107
Book 1.indb 107
03/04/2018 16:44:31
Directors’ remuneration report
Executive directors interests
Deferred shares (audited)a
Bob Dudleyb
Brian Gilvary
Bonus
year
2013
2014
Type
Comp
Mat
Comp
Vol
Mat
2015f Comp
Vol
Mat
2016g Comp
Mat
Comp
Mat
Comp
Vol
Mat
2015f Comp
Vol
Mat
2016g Comp
Mat
2013
2014
Performance
period
2014-2016
2014-2016
2015-2017d
2015-2017d
2015-2017d
2016-2018d
2016-2018d
2016-2018d
2017-2019
2017-2019d
2014-2016
2014-2016
2015-2017
2015-2017
2015-2017e
2016-2018
2016-2018
2016-2018
2017-2019
2017-2019h
Deferred share element interests
Potential maximum deferred shares
Date of award of
deferred shares
12 Feb 2014
12 Feb 2014
11 Feb 2015
11 Feb 2015
11 Feb 2015
4 Mar 2016
4 Mar 2016
4 Mar 2016
19 May 2017
19 May 2017
12 Feb 2014
12 Feb 2014
11 Feb 2015
11 Feb 2015
11 Feb 2015
4 Mar 2016
4 Mar 2016
4 Mar 2016
19 May 2017
19 May 2017
At 1 Jan
2017
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
–
–
Awarded
2017
–
–
–
–
–
–
–
–
147,642
147,642
–
–
–
–
–
–
–
–
73,070
73,070
At 31 Dec
2017
–
–
147,054
147,054
294,108
275,892
275,892
551,784
147,642
147,642
–
–
88,288
88,288
176,576
159,021
159,021
318,042
73,070
73,070
Interests vested in 2017 and 2018
Number of
ordinary shares
vested
–
–
–
–
–
–
–
–
Vesting date
183,732c 24 Feb 2017
183,732c 24 Feb 2017
–
–
–
–
–
–
–
–
119,157c 24 Feb 2017
119,157c 24 Feb 2017
109,502c 20 Feb 2018
109,502c 20 Feb 2018
–
–
–
–
–
–
–
–
–
–
–
–
£
Face value
of the award
–
–
655,861
655,861
1,311,722
1,015,283
1,015,283
2,030,565
697,092
697,092
–
–
–
–
787,529
585,197
585,197
1,170,395
345,000
345,000
Former executive directors
Iain Conn
2013 Comp
Mat
2014-2016
2014-2016
12 Feb 2014
12 Feb 2014
100,563
33,521i
–
–
–
–
123,977c 24 Feb 2017
41,325c 24 Feb 2017
–
–
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 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 24 February 2017 and 20 February 2018 were £4.47 and £4.75 respectively and for
ADSs on 24 February 2017 was $33.50. These totals include the additional accrual of dividends which vested on 19 May 2017 and 2 August 2017.
d 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. The market
price of ordinary shares used to determine the total value at vesting on 11 February 2015 was £4.46.
e Brian Gilvary has voluntarily agreed to defer vesting of these awards for five years with a further one year retention period.
f The face value has been calculated using the market price of ordinary shares on 4 March 2016 of £3.68.
g The market price at closing of ordinary shares on 19 May 2017 was £4.72 and for ADSs was $36.94. The sterling value has been used to calculate the face value.
h Brian Gilvary has voluntarily agreed to defer vesting of these awards until the later of three years post award or one year post retirement, therefore the performance period is expected to
exceed the minimum term of three years.
i 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.
108
BP Annual Report and Form 20-F 2017
Book 1.indb 108
03/04/2018 16:44:32
Directors’ remuneration report
Performance shares (audited)
Share element interests
Interests vested in 2017 and 2018
Bob Dudleyb
Brian Gilvary
Performance period
2014-2016
2015-2017
2016-2018f
2017-2019f
2014-2016
2015-2017
2016-2018f
2017-2019f
Date of award
of performance
shares
12 Feb 2014
11 Feb 2015
4 Mar 2016
19 May 2017
12 Feb 2014
11 Feb 2015
4 Mar 2016
19 May 2017
Potential maximum performance sharesa
At 1 Jan
2017
1,304,922
1,501,770
1,809,582
–
605,544
685,246
786,559
–
Awarded
2017
–
–
–
1,571,628
–
–
–
722,093
At 31 Dec
2017
–
1,365,240e
1,645,074e
1,428,750e
–
685,246
786,559
722,093
Number of
ordinary
shares
vested
1,172,484
–
–
Vesting date
653,538c 19 May 2017d
May 2018
–
–
308,286c 19 May 2017d
May 2018
594,932
–
–
–
–
£
Face value
of the award
–
–
6,053,872
6,743,700
–
–
2,894,537
3,409,362
Former executive directors
Iain Conn
2014-2016
12 Feb 2014
220,043
–
–
112,025c g 19 May 2017d
–
a For awards under the 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. 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, each of the strategic imperatives and strategic progress reaching the minimum threshold, has been calculated. For awards under
the 2017-2019 plan, performance conditions are measured 50% on TSR relative to ExxonMobil, Shell, Total and Chevron over three years; 30% on ROACE based on performance in 2019 and
20% on strategic progress assessed over the performance period. Each performance period ends on 31 December of the third year.
b Bob Dudley 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 19 May 2017 was £4.72 and for ADSs was $36.94. For the assumed vestings dated May 2018 a price of £5.01 per ordinary share
and $39.85 per ADS has been used. These are the average prices from the fourth quarter of 2017. These totals include the additional accrual of dividends which vested on 2 August 2017.
d The 2014-2016 award vested on 19 May 2017, which resulted in an increase in value at vesting of £24,644 for Iain Conn. Details for Bob Dudley and Brian Gilvary can be found in the single
figure table on page 95.
e Bob Dudley has requested that the EDIP performance shares vestings in respect of the performance periods 2015-2017 and 2016-2018 are based on the 500% maximum annual award level
which applies under the 2017 directors’ remuneration policy, rather than the 550% maximum annual award level which applies under the 2014 directors’ remuneration policy.
f The market price at closing of ordinary shares on 4 March 2016 was £3.68 and for ADSs was $31.15 and on 19 May 2017 was £4.72 and for ADSs was $36.94.
g Potential maximum of performance shares element has been pro-rated to reflect actual service during the performance period.
C
o
r
p
o
r
a
t
e
g
o
v
e
r
n
a
n
c
e
Share interests in share options plans (audited)
Brian Gilvary
Option type At 1 Jan 2017
500,000
BP 2011
3,103
SAYE
Granted
–
–
Exercised
–
–
At 31 Dec
2017
500,000
3,103
Option price
£3.72
£2.90
Market price at
date of exercise
Date from which
first exercisable
Expiry date
– 07 Sep 2014 07 Sep 2021
– 01 Sep 2019 28 Feb 2020
The closing market prices of an ordinary share and of an ADS on 29 December 2017 were £5.227 and $42.03 respectively.
During 2017 the highest market prices were £5.247 and $42.03 respectively and the lowest market prices were £4.3975 and $33.31 respectively.
BP 2011 = BP 2011 plan. These options were granted to Brian Gilvary prior to his appointment as a director and are not subject to performance conditions.
Book 1.indb 109
03/04/2018 16:44:32
BP Annual Report and Form 20-F 2017
109
Directors’ remuneration report
Remuneration policy table – executive directors
A summary of the remuneration policy approved by shareholders at the 2017 AGM is set out below. For the full remuneration policy, please refer
to the 2016 Directors' remuneration report at bp.com/remuneration.
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 2018 AGM, the annual salaries for the
executive directors will be:
– Group chief executive – Bob Dudley: $1,854,000.
– Chief financial officer – Brian Gilvary: £775,000.
• 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 in policy, see bp.com/remuneration.
• 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.
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Directors’ remuneration report
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 2018 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 2018 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,
See bp.com/remuneration.
• 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.
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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.
BP Annual Report and Form 20-F 2017
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Directors’ remuneration report
Remuneration 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 29 March 2018.
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Directors’ 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 IFRS 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.
Having made the requisite enquiries, so far as the directors are aware,
there is no relevant audit information (as defined by Section 418(3) of the
Companies Act 2006) of which the company’s auditors are unaware,
and the directors have taken all the steps they ought to have taken to
make themselves aware of any relevant audit information and to
establish that the company’s auditors are aware of that information.
The directors confirm that to the best of their knowledge:
• The consolidated financial statements, prepared in accordance with
IFRS as issued by the IASB, IFRS as adopted by the EU and in
accordance with the provisions of the Companies Act 2006, give a true
and fair view of the assets, liabilities, financial position and profit or loss
of the group.
• The parent company financial statements, prepared in accordance
with United Kingdom generally accepted accounting practice, give a
true and fair view of the assets, liabilities, financial position,
performance and cash flows of the company.
• 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.
C-H Svanberg
Chairman
29 March 2018
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.
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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 57. 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 55.
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 77-89.
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.
This page does not form part of BP’s Annual Report on Form 20-F as filed with the SEC.
BP Annual Report and Form 20-F 2017
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An audit committee meeting in February 2018 carried out an annual
review of the effectiveness of the system of internal control. In
considering this system, the audit committee 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.
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 audit committee was
satisfied that these were or are being appropriately addressed by the
remedial actions proposed by management.
At its meeting in March 2018, the board considered the review
undertaken by the audit committee and the proposed disclosures
outlining the company’s risk management and internal control systems
prior to publication of the annual report and accounts.
A statement regarding the company’s internal controls over financial
reporting is set out on page 275.
Longer-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
on page 57, 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 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.
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Financial
statements
116 Consolidated financial statements of the BP group
Independent auditor’s
reports
Group income statement
Group statement of
comprehensive income
116
125
126
Group statement of
changes in equity
Group balance sheet
Group cash flow statement
127
128
129
1.
2.
130
3.
4.
5.
6.
7.
8.
9.
10.
143
145
147
150
150
151
153
153
130 Notes on financial statements
Significant accounting
policies
Significant event – Gulf of
Mexico oil spill
Disposals and impairment
Segmental analysis
Income statement analysis
Exploration expenditure
Taxation
Dividends
Earnings per share
Property, plant and
equipment
Capital commitments
Goodwill
Intangible assets
Investments in joint ventures
Investments in
associates
Other investments
Inventories
Trade and other
receivables
Valuation and qualifying
accounts
Trade and other payables
Provisions
155
155
156
157
158
11.
12.
13.
14.
15.
158
160
160
161
161
162
16.
17.
18.
20.
21.
161
19.
22.
23.
24.
25.
26.
27.
28.
29.
30.
31.
32.
33.
34.
35.
36.
Pensions and other post-
retirement benefits
Cash and cash equivalents
Finance debt
Capital disclosures and
analysis of changes in
net debt
Operating leases
Financial instruments and
financial risk factors
Derivative financial
instruments
Called-up share capital
Capital and reserves
Contingent liabilities
Remuneration of senior
management and non-
executive directors
Employee costs and
numbers
Auditor’s remuneration
Subsidiaries, joint
arrangements and
associates
Condensed consolidating
information on certain US
subsidiaries
191 Supplementary information on oil and natural gas
(unaudited)
Oil and natural gas
exploration and production
activities
Movements in estimated
net proved reserves
192
198
Standardized measure of
discounted future net cash
flows and changes therein
relating to proved oil and
gas reserves
Operational and statistical
information
219
Parent company financial statements of BP p.l.c.
Company balance sheet
Company statement of
changes in equity
Notes on financial
statements
220
219
221
6.
7.
8.
9.
10.
11.
12.
13.
14.
Taxation
Called-up share capital
Capital and reserves
Financial guarantees
Share-based payments
Auditor’s remuneration
Directors’ remuneration
Employee costs and
numbers
Related undertakings
1.
2.
3.
4.
5.
Significant
accounting policies
Investments
Receivables
Pensions
Payables
221
223
224
224
227
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168
169
169
170
173
177
178
181
182
183
183
184
185
213
216
228
228
229
229
230
230
230
230
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BP Annual Report and Form 20-F 2017
BP Annual Report and Form 20-F 2017
115
115
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
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 2017 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. which comprise:
Group
Parent company
Group balance sheet as at 31 December 2017.
Group income statement for the year then ended.
Group statement of comprehensive income for the year then ended.
Balance sheet as at 31 December 2017.
Statement of changes in equity for the year then ended.
Related Notes 1 to 14 to the financial statements, including a
summary of significant accounting policies.
Group statement of changes in equity for the year then ended.
Group cash flow statement for the year then ended.
Related Notes 1 to 36 to the financial statements, including a summary of
significant accounting policies.
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 including FRS 101 (United
Kingdom generally accepted accounting practice).
Basis for opinion
We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our responsibilities under
those standards are further described in the Auditor’s responsibilities for the audit of the financial statements section of our report below. We
are independent of the group and parent company in accordance with the ethical requirements that are relevant to our audit of the financial
statements in the UK, including the FRC’s Ethical Standard as applied to listed public interest entities, and we have fulfilled our other ethical
responsibilities in accordance with these requirements.
We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.
Use of our report
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.
Conclusions relating to principal risks, going concern and viability statement
We have nothing to report in respect of the following information in the annual report, in relation to which the ISAs (UK) require us to report to
you whether we have anything material to add or draw attention to:
• the disclosures in the annual report set out on page 57 that describe the principal risks and explain how they are being managed or mitigated;
• the directors’ confirmation set out on page 113 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 directors’ statement set out on page 114 in the annual report about whether they considered it appropriate to adopt the going concern
basis of accounting in preparing the financial statements, 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;
• whether the directors’ statement in relation to going concern required under the Listing Rules in accordance with Listing Rule 9.8.6R(3) is
materially inconsistent with our knowledge obtained in the audit; or
• the directors’ explanation set out on page 114 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.
This page does not form part of BP's Annual Report on Form 20-F as filed with the SEC.
116
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Key audit matters
Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial statements of
the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) that we identified.
These matters included those which had the greatest effect on the overall audit strategy, the allocation of resources in the audit and in
directing the efforts of the engagement team. These matters were addressed in the context of our audit of the financial statements as a
whole, and in our opinion thereon, and we do not provide a separate opinion on these matters.
Key observations
communicated to the Audit
Committee
There remains
uncertainty around the
BEL provision, in
particular the unresolved
claims and claims under
appeal, as the amounts
payable may differ from
those provided.
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.
Risk
Our response to the risk
The determination of the liabilities, contingent
liabilities and disclosures arising from the Gulf of
Mexico oil spill (as described on page 79 of the report
of the audit committee and Note 2 of the financial
statements).
There is particular 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.
The total amount recognized as an increase in
provisions in relation to the Gulf of Mexico oil spill
during the year was $2,647 million relating to business
economic loss (‘BEL’) and other claims associated with
the Court Supervised Settlement Program ('CSSP').
The increase is predominantly a result of significantly
higher average BEL claims determinations issued by
the CSSP during the fourth quarter and the continuing
effect arising from the Policy 495 ruling. The remaining
provision as at 31 December 2017 was $2,580 million.
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 reviewed audit enquiry response letters from
external legal counsel and read determinations and
judgements 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.
• We reconciled the number of undetermined
claims to third party claims management data.
• We performed a detailed review of the status and
expected outcome of the significant claims
within appeals, which included discussion with
the group general counsel.
• We performed sensitivity analyses over average
cost per claim assumptions and assessed the
potential effect on the provision.
• We considered events that took place after the
balance sheet date and before the issuance of
this report and ensured these were reflected
appropriately.
• We assessed the remaining economic loss and
property damage claims from individuals and
businesses that either opted out of the Plaintiffs’
Steering Committee ('PSC') settlement and/or were
excluded from that settlement. We validated a
sample of claims to third party data, assessing the
year end closing payable 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 circumstances.
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BP Annual Report and Form 20-F 2017
117
Key observations
communicated 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.
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 80 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.
Our procedures were performed by team members
with significant experience of the process of
estimating oil and gas reserves and resources,
including the primary audit engagement team and
component teams at 9 Upstream components.
• We confirmed our understanding and tested key
management controls related to the reserves and
resources estimation process. This included
management's review and approval of estimated
volumes.
• We tested the controls over the group's
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 that these parties are appropriate in their
roles within the estimation process.
• We confirmed that significant changes in reserves
and resources were made in the appropriate period,
and were in compliance with BP's discovered
resources management policy (‘DRM’) and SEC
regulations.
• Where reserve and resources volumes have a
material impact on the financial statements, we
validated these volumes and assumptions against
underlying information and documentation as
required by the DRM.
• We validated that the updated reserves and
resources estimates were included appropriately in
the group’s consideration of oil and gas asset
impairment valuations and in accounting for DD&A.
Unauthorized trading activity within the integrated
supply and trading function has the potential to
impact revenue and profits (as described within the
group's principal risks on page 58 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 on trading activities were performed
by component teams and the primary engagement
team at 7 components across the UK, US and
Singapore.
Based on our procedures
we identified no matters
to report to the Audit
Committee.
• 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 independently confirming a sample of trades
with third parties.
• We verified the fair value of a sample of derivatives
using contract and external market prices. For
derivative instruments where observable market
data is not available we have independently
validated the internal valuation models
management used to determine fair value.
• 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.
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118
BP Annual Report and Form 20-F 2017
Risk
Our response to the risk
US Tax Reform (as described on page 81 of the report
of the Audit committee and Note 1 of the financial
statements).
Audit procedures were performed by team members
and EY tax experts with significant experience of the
US corporate tax system.
On 22 December 2017, the US Tax Cuts and Jobs Act
(‘TCJA’) was signed into law, enacting widespread
changes to US fiscal law.
The group recognized a one-off taxation charge of $0.9
billion for the year ended 31 December 2017, in respect
of the remeasurement of deferred tax balances as a
result of the reduction in the US federal corporate
income tax rate from 35% to 21%.
We focused on this area due to the complexity and
extent of the US tax reform package, the requirement
for the group to determine and account for the effects
of the change close to its year end and the material
impact on the group’s profit for the year.
• We verified that the internal controls over financial
reporting were designed appropriately to enable
the accounting implications of US tax reform to be
accurately recorded in the financial statements.
• We assessed the tax accounting implications on
existing deferred tax assets and liabilities based on
the enacted 21% corporate rate. We tested and
confirmed that the methodology used by
management to calculate the estimated liability
was based on an acceptable interpretation of the
TCJA legislation.
• We verified the analysis performed by
•
management to determine the appropriate
presentation, in accordance with IAS 12, of the
impact of tax changes recorded through the
income statement and statement of other
comprehensive income.
We performed procedures to evaluate
management’s assessment of other key US tax
reform changes which may affect the group’s 2017
income tax position, including the one-time
transition tax, anti-base erosion measures and
expected realization of foreign tax credits.
Key observations
communicated to the Audit
Committee
Based on the audit
procedures specifically
designed and performed
to respond to the impact
of US tax reform on the
group, we concluded
that management’s
computation of the tax
accounting assessments
and adjustments is
calculated in compliance
with IAS 12. The
appropriate presentation
and disclosures are
made in the financial
statements at 31
December 2017.
Due to the nature and
circumstances around
US tax reform, the
presentation of the $0.9
billion charge as a non-
operating item is
appropriately disclosed.
Changes from the prior year
Our risk assessment and audit approach evolve as circumstances which impact the group’s business or financial statements change. In the
prior year, our auditor’s report included a key audit matter in relation to the macroeconomic environment at the time which had the potential to
materially impact the carrying value of the Group Upstream’s non-current assets. This risk has been downgraded in 2017. In our view, the
macroeconomic environment no longer represents a significant risk for our audit, given the fact that the impairment indicators identified in
2016 have subsided through 2017, mainly as a result of sustained increases in oil prices. In the current year, our auditor’s report includes a key
audit matter in relation to US Tax Reform due to the matters set out above.
An overview of 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 55 components
covering the UK, US, Abu Dhabi, Angola, Azerbaijan, Brazil, Egypt, Germany, India, Russia, Singapore, Trinidad and Tobago and the group
functions, representing the principal business units within the group.
Of the 55 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 46 components (“specific scope components”), we
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 30% of the group’s profit before tax (2016 29%), 42% of the group’s revenue (2016
41%) and 10% of the group’s property, plant and equipment (2016 10%). The specific scope components contributed 32% of the group’s profit
before tax (2016 32%), 30% of the group’s revenue (2016 26%) and 52% of the group’s property, plant and equipment (2016 54%). 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 46 specific scope components, we instructed 14 of these locations to
perform specified procedures over goodwill, intangible assets, the carrying value of certain investments held by the group, gain on sale of
businesses and fixed assets, interest and other income, exploration expenses, sales and other operating revenues and production taxes.
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 0.13% of the total group profit before tax and
0.13% 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.
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BP Annual Report and Form 20-F 2017
119
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 46 specific scope components, audit procedures were performed on 24 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 Abu Dhabi, Azerbaijan, Egypt, Germany, India, Russia, Singapore, the UK 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 (UK) 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 (2016 $0.5 billion). For the 2017 audit, we deemed it appropriate to determine our
materiality based on 5% of the group's underlying replacement cost profit (as defined on page 293) before interest and taxation for 2017. Due
to the recovery and stability in oil and gas prices through 2017 we no longer view it as necessary to determine materiality based on normalizing
current year expected underlying replacement cost profit before interest and taxation and how those results would look if oil and gas prices
forecast by the company for 2018 and 2019 had prevailed in the 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 250 of the Annual Report and
Form 20-F 2017.
We determined materiality for our audit of the standalone parent company financial statements to be $1,300 million (2016 $1,300 million),
which is 1% (2016 1%) of equity. The materiality determined for the standalone parent company financial statements exceeds the group
materiality as it is determined on a different basis given the nature of the operations. For the purposes of the audit of the group financial
statements, our procedures, including those on balances in the parent company, are undertaken with reference to the group materiality and
performance materiality set out in this report.
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% (2016 75%) of our materiality, namely $375 million (2016 $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.
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 $300 million (2016 $75 million to $281 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 (2016 $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.
Other information
The other information comprises the information included in the Annual Report other than the financial statements and our auditor’s report
thereon. The directors are responsible for the other information.
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120
BP Annual Report and Form 20-F 2017
Our opinion on the financial statements does not cover the other information and, except to the extent otherwise explicitly stated in this report,
we do not express any form of assurance conclusion thereon.
In connection with our audit of the financial statements, our responsibility is to read the other information and, in doing so, consider whether
the other information is materially inconsistent with the financial statements or our knowledge obtained in the audit, or otherwise appears to
be materially misstated. If we identify such material inconsistencies or apparent material misstatements, we are required to determine
whether there is a material misstatement in the financial statements or a material misstatement of the other information. If, based on the work
we have performed, we conclude that there is a material misstatement of the other information, we are required to report that fact.
We have nothing to report in this regard.
In this context, we also have nothing to report in regard to our responsibility to specifically address the following items in the other information
and to report as uncorrected material misstatements of the other information where we conclude that those items meet the following
conditions:
• Fair, balanced and understandable set out on page 114 – the statement given by the directors that they consider 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 group’s performance, business model and strategy, is materially inconsistent with our knowledge obtained in the audit; or
• Audit committee reporting set out on pages 77-83 – the section describing the work of the audit committee does not appropriately address
matters communicated by us to the audit committee; or
• Directors’ statement of compliance with the UK Corporate Governance Code set out on page 113 – the parts of the directors’ statement
required under the Listing Rules relating to the company’s compliance with the UK Corporate Governance Code containing provisions
specified for review by the auditor in accordance with Listing Rule 9.8.10R(2) do not properly disclose a departure from a relevant provision
of the UK Corporate Governance Code.
Opinions 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.
In our opinion, 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; and
the Strategic report and the Directors' report have been prepared in accordance with applicable legal requirements.
Matters on which we are required to report by exception
In light of the knowledge and understanding of the group and the parent company and its environment obtained in the course of the audit, we
have not identified material misstatements in the Strategic report or the Directors’ report.
We have nothing to report in respect of the following matters in relation to which the Companies Act 2006 requires us to report to you if, in our
opinion:
• adequate accounting records have not been kept by the parent company, or returns adequate for our audit have not been received from
•
branches not visited by us; or
the parent company financial statements and the part of the Directors’ remuneration report to be audited are not in agreement with the
accounting records and returns; or
• certain disclosures of directors’ remuneration specified by law are not made; or
• we have not received all the information and explanations we require for our audit.
Responsibilities of directors
As explained more fully in the Statement of directors’ responsibilities set out on page 113, the directors are responsible for the preparation of
the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the directors determine is
necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, the directors are responsible for assessing the group and parent company’s ability to continue as a going
concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either
intend to liquidate the group or the parent company or to cease operations, or have no realistic alternative but to do so.
Auditor’s responsibilities for the audit of the financial statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement,
whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but
is not a guarantee that an audit conducted in accordance with ISAs (UK) will always detect a material misstatement when it exists.
Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected
to influence the economic decisions of users taken on the basis of these financial statements.
Explanation as to what extent the audit was considered capable of detecting irregularities, including fraud
The objectives of our audit, in respect to fraud, are; to identify and assess the risks of material misstatement of the financial statements due to
fraud; to obtain sufficient appropriate audit evidence regarding the assessed risks of material misstatement due to fraud, through designing
and implementing appropriate responses; and to respond appropriately to fraud or suspected fraud identified during the audit. However, the
primary responsibility for the prevention and detection of fraud rests with both those charged with governance of the entity and management.
Our approach was as follows:
• We obtained an understanding of the legal and regulatory frameworks that are applicable to the group and determined that the most
significant are those that relate to the reporting framework (IFRS, FRS 101, the Companies Act 2006, UK Corporate Governance Code and
US Securities Exchange Act of 1934) and the relevant tax compliance regulations in the jurisdictions in which the group operates. In
addition, we concluded that there are certain significant laws and regulations which may have an effect on the determination of the
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BP Annual Report and Form 20-F 2017
121
amounts and disclosures in the financial statements being the Listing Rules of the UK Listing Authority, and those laws and regulations as
disclosed within Regulation of the group’s business on pages 265-270 and International trade sanctions on pages 273-274.
• We understood how the group is complying with those frameworks by making enquiries of management, internal audit, those
responsible for legal and compliance procedures and the group general counsel. We corroborated our enquiries through the attendance at
meetings held by the audit, disclosure and safety, ethics and environment assurance committees. We designed our audit procedures to
identify non-compliance with such laws and regulations identified in the paragraph above. As well as enquiry and attendance at meetings,
our procedures involved a review of the reporting to the above committees and a review of board meetings and other committee minutes
to identify any non-compliance with laws and regulations.
• We assessed the susceptibility of the group’s financial statements to material misstatement, including how fraud might occur by meeting
with management to understand where they considered there was susceptibility to fraud. We also considered performance targets and
their propensity to influence management to manage earnings and revenue by overriding internal controls. We considered the controls
that the group has established to address risks identified, or that otherwise prevent, deter and detect fraud; and how senior management
monitors those controls. We performed specific procedures to respond to the fraud risk of unauthorized trading as referred to in the key
audit matters section above. Our procedures also included testing a risk-based sample of manual journals that may have been posted
with the intention of overriding internal controls to manipulate earnings. These procedures were designed to provide reasonable
assurance that the financial statements were free from fraud or error.
• The group operates in the oil and gas industry which is a highly regulated environment. As such the Senior Statutory Auditor reviewed the
experience and expertise of the engagement team to ensure that the team had the appropriate competence and capabilities, which
included the use of an expert where appropriate.
A further description of our responsibilities for the audit of the financial statements is located on the Financial Reporting Council’s website at
https://www.frc.org.uk/auditorsresponsibilities. This description forms part of our auditor’s report.
Other matters we are required to address
• We were appointed by the company on 17 May 2017 to audit the financial statements for the year ended 31 December 2017.
• The period of total uninterrupted engagement including previous renewals and reappointments is over 100 years, covering the year ended
1909 to the year ended 31 December 2017.
• The non-audit services prohibited by the FRC’s Ethical Standard were not provided to the group or the parent company and we remain
independent of the group and the parent company in conducting the audit.
• The audit opinion is consistent with the additional report to the audit committee.
John C. Flaherty (Senior Statutory Auditor)
for and on behalf of Ernst & Young LLP, Statutory Auditor
London
29 March 2018
1.
2.
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.
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122
BP Annual Report and Form 20-F 2017
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on the financial statements
We have audited the accompanying group balance sheets of BP p.l.c. (the Company) as of 31 December 2017 and 2016, 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 2017, and the related notes (collectively referred to as the "group financial statements"). In
our opinion, the group financial statements present fairly, in all material respects, the financial position of BP p.l.c. at 31 December 2017 and
2016 and the results of its operations and its cash flows for each of the three years in the period ended 31 December 2017, in conformity with
International Financial Reporting Standards ("IFRS") as adopted by the European Union and IFRS 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) (PCAOB), BP
p.l.c.’s internal control over financial reporting as of 31 December 2017, 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 29 March 2018 expressed
an unqualified opinion thereon.
Basis for opinion
These financial statements are the responsibility of BP p.l.c.'s management. Our responsibility is to express an opinion on these financial
statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect
to BP p.l.c. in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange
Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud,
and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts
and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made
by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable
basis for our opinion.
/s/ Ernst & Young LLP
We have served as the Company's auditor since 1909.
London, United Kingdom
29 March 2018
1.
2.
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.
BP Annual Report and Form 20-F 2017
123
Consolidated financial statements of the BP group
Report of Independent Registered Public Accounting Firm
To the shareholders and board of directors of BP p.l.c.
Opinion on internal control over financial reporting
We have audited BP p.l.c.’s internal control over financial reporting as of 31 December 2017, based on criteria established in the UK Financial
Reporting Council’s Guidance on Risk Management, Internal Control and Related Financial and Business Reporting. In our opinion, BP p.l.c.
maintained, in all material respects, effective internal control over financial reporting as of 31 December 2017, 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) (PCAOB), the
group balance sheets of BP p.l.c. as of 31 December 2017 and 2016, 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 2017, and our report dated 29 March 2018 expressed an unqualified opinion thereon.
Basis for opinion
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 275. Our responsibility is to express an opinion on the company’s internal control over financial reporting based on our audit.
We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the company in accordance
with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. 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.
Definition and limitations of internal control over financial reporting
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.
/s/ Ernst & Young LLP
London, United Kingdom
29 March 2018
Consent of independent registered public accounting firm
We consent to the incorporation by reference of our reports dated 29 March 2018, 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 2017 in the following Registration Statements:
Registration Statements on Form F-3 (File Nos. 333-208478 and 333-208478-01) of BP p.l.c. and BP Capital Markets 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
29 March 2018
1.
2.
124
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.
BP Annual Report and Form 20-F 2017
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
Profit (loss) for the year attributable to BP shareholders
Per ordinary share (cents)
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
2017
2016
4
14
15
5
3
17
4
4
3
6
5
22
7
9
9
9
9
240,208
1,177
1,330
657
1,210
244,582
179,716
24,229
1,775
15,584
1,216
2,080
10,508
9,474
2,074
220
7,180
3,712
3,468
3,389
79
3,468
17.20
17.10
1.03
1.03
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
$ million
2015
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)
BP Annual Report and Form 20-F 2017
125
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
Currency translation differences
Exchange (gains) losses on translation of foreign operations reclassified to gain or loss
on 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
Note
28
28
28
14, 15
7
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
22
14, 15
7
Other comprehensive income
Total comprehensive income
Attributable to
BP shareholders
Non-controlling interests
a See Note 30 for further information.
2017
3,468
1,986
(120)
14
197
116
112
564
(196)
2,673
3,646
—
(1,303)
2,343
5,016
8,484
8,353
131
8,484
2016
172
254
30
1
(639)
196
81
833
13
769
(2,496)
—
739
(1,757)
(988)
(816)
(846)
30
(816)
$ million
2015
(6,400)
(4,119)
23
1
(178)
249
22
(814)
257
(4,559)
4,139
(1)
(1,397)
2,741
(1,818)
(8,218)
(8,259)
41
(8,218)
126
BP Annual Report and Form 20-F 2017
Group statement of changes in equitya
At 1 January 2017
Profit (loss) for the year
Other comprehensive income
Total comprehensive income
Dividendsb
Repurchase 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,
net of tax
At 31 December 2017
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,
net of tax
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,
net of tax
At 31 December 2015
a See Note 30 for further information.
b See Note 8 for further information.
$ million
Share
capital and
capital
reserves
46,122
—
—
—
—
—
—
Treasury
shares
(18,443)
—
—
—
—
—
1,485
—
—
—
—
Foreign
currency
translation
reserve
(6,878)
—
1,722
1,722
—
—
—
—
—
Fair value
reserves
Profit and
loss
account
BP
shareholders'
equity
Non-
controlling
interests Total equity
(1,153)
—
410
410
—
—
—
—
—
75,638
3,389
2,832
6,221
(6,153)
(343)
(798)
215
446
95,286
3,389
4,964
8,353
(6,153)
(343)
687
215
446
1,557
79
52
131
(141)
—
—
—
366
96,843
3,468
5,016
8,484
(6,294)
(343)
687
215
812
46,122
(16,958)
(5,156)
(743)
75,226
98,491
1,913
100,404
43,902
—
—
—
—
2,220
—
—
(19,964)
—
—
—
—
1,521
—
—
(7,267)
—
389
389
—
—
—
—
(823)
—
(330)
(330)
—
—
—
—
81,368
115
(1,020)
(905)
(4,611)
(750)
106
430
97,216
115
(961)
(846)
(4,611)
2,991
106
430
1,171
57
(27)
30
(107)
—
—
463
98,387
172
(988)
(816)
(4,718)
2,991
106
893
46,122
(18,443)
(6,878)
(1,153)
75,638
95,286
1,557
96,843
43,902
—
—
—
—
—
—
—
(20,719)
—
—
—
—
755
—
—
(3,409)
—
(3,858)
(3,858)
—
—
—
—
(897)
—
74
74
—
—
—
—
92,564
(6,482)
2,007
(4,475)
(6,659)
(99)
40
(3)
111,441
(6,482)
(1,777)
(8,259)
(6,659)
656
1,201
82
(41)
41
(91)
—
112,642
(6,400)
(1,818)
(8,218)
(6,750)
656
40
(3)
—
20
40
17
43,902
(19,964)
(7,267)
(823)
81,368
97,216
1,171
98,387
BP Annual Report and Form 20-F 2017
127
Note
2017
10
12
13
14
15
16
18
28
7
22
17
18
28
16
23
20
28
24
21
20
28
24
7
21
22
30
30
30
129,471
11,551
18,355
7,994
16,991
1,245
185,607
646
1,434
4,110
1,112
4,469
4,169
201,547
190
19,011
24,849
3,032
1,414
761
125
25,586
74,968
276,515
44,209
2,808
4,960
7,739
1,686
3,324
64,726
13,889
3,761
505
55,491
7,982
20,620
9,137
111,385
176,111
100,404
98,491
1,913
100,404
$ million
2016
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
259
17,655
20,675
3,016
1,486
1,194
44
23,484
67,813
263,316
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
108,119
166,473
96,843
95,286
1,557
96,843
Group balance sheet
At 31 December
Non-current assets
Property, plant and equipment
Goodwill
Intangible assets
Investments in joint ventures
Investments in associates
Other investments
Fixed assets
Loans
Trade and other receivables
Derivative financial instruments
Prepayments
Deferred tax assets
Defined benefit pension plan surpluses
Current assets
Loans
Inventories
Trade and other receivables
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Total assets
Current liabilities
Trade and other payables
Derivative financial instruments
Accruals
Finance debt
Current tax payable
Provisions
Non-current liabilities
Other payables
Derivative financial instruments
Accruals
Finance debt
Deferred tax liabilities
Provisions
Defined benefit pension plan and other post-retirement benefit plan deficits
Total liabilities
Net assets
Equity
BP shareholders’ equity
Non-controlling interests
Total equity
C-H Svanberg Chairman
R W Dudley Group chief executive
29 March 2018
128
BP Annual Report and Form 20-F 2017
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
Expenditure on property, plant and equipment, intangible and other assets
Acquisitions, net of cash acquired
Investment in joint ventures
Investment in associates
Total cash capital expenditure
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
2017
2016
$ million
2015
7,180
(2,295)
(9,571)
6
4
3
5
22
22
3
3
8
1,603
15,584
6
(2,507)
1,253
(304)
375
2,074
(1,572)
220
661
(394)
2,106
(848)
(4,848)
2,344
(4,002)
18,931
(16,562)
(327)
(50)
(901)
(17,840)
2,936
478
349
(14,077)
(343)
8,712
(6,276)
(158)
1,063
(6,153)
(141)
(3,296)
544
2,102
23,484
25,586
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
(16,701)
(1)
(50)
(700)
(17,452)
1,372
1,259
68
(14,753)
—
12,442
(6,685)
51
887
(4,611)
(107)
1,977
(820)
(2,905)
26,389
23,484
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
(18,648)
23
(265)
(1,312)
(20,202)
1,066
1,726
110
(17,300)
—
8,173
(6,426)
473
(5)
(6,659)
(91)
(4,535)
(672)
(3,374)
29,763
26,389
BP Annual Report and Form 20-F 2017
129
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 2017 were approved and signed by the group chief
executive and chairman on 29 March 2018 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 2017. 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; provisions and contingencies, including provisions and contingencies related to the Gulf of Mexico oil spill; pensions and
other post-retirement benefits; and income taxes. Where an estimate has a significant risk of resulting in a material adjustment to the carrying
amounts of assets and liabilities within the next financial year this is specifically noted within the boxed text. Whilst the impact of the
application of hedge accounting on the group’s financial statements can be significant, the group no longer considers the decision to apply
such accounting to represent one of its significant accounting judgements.
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 12 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.
130
BP Annual Report and Form 20-F 2017
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant judgement: investment in Rosneft
Judgement is required in assessing the level of control or influence over another entity in which the group holds an interest. For BP, the
judgement that the group has significant influence over Rosneft Oil Company (Rosneft), a Russian oil and gas company is significant. As a
consequence of this judgement, BP uses the equity method of accounting for its investment and BP's share of Rosneft's oil and natural gas
reserves is included in the group's estimated net proved reserves of equity-accounted entities. If significant influence was not present, the
investment would be accounted for as an available-for-sale financial asset as described under 'Financial assets' below and no share of
Rosneft's oil and natural gas reserves would be reported.
Significant influence is defined in IFRS as the power to participate in the financial and operating policy decisions of the investee but is not
control or joint control of those policies. Significant influence is presumed when an entity owns 20% or more of the voting power of the
investee. Significant influence is presumed not to be present when an entity owns less than 20% of the voting power of the investee.
BP owns 19.75% of the voting shares of Rosneft. The Russian federal government, through its investment company JSC Rosneftegaz,
owned 50% plus one share of the voting shares of Rosneft at 31 December 2017. 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 chairman 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. BP's management consider, therefore, that the group has significant influence over Rosneft, as defined by IFRS.
The equity method of accounting
Under the equity method, an 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 in the
accounting policies used by the equity-accounted entity and those used by BP, 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 4.
Foreign currency translation
In individual subsidiaries, joint ventures and associates, transactions in foreign currencies are initially recorded in the functional currency of
those entities 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.
BP Annual Report and Form 20-F 2017
131
1. Significant accounting policies, judgements, estimates and assumptions – continued
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.
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 fifteen 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.
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 or appraisal work in the area, remain capitalized on the balance sheet as long as such work is
under way or firmly planned.
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
Judgement is required to determine whether it is appropriate to continue to carry costs associated with exploration wells and exploratory-
type stratigraphic test wells on the balance sheet. It is not unusual to have such costs 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 circumstances that indicate 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 that were scheduled to expire at the end of 2013 and some with terms that 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, directly attributable finance costs. The purchase
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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 with estimated future capital expenditure expected to be incurred relating to as yet undeveloped reserves expected to be processed
through these common facilities.
Other property, plant and equipment is depreciated on a straight-line basis over its expected useful life. The typical useful lives of the group’s
other property, plant and equipment are as follows:
Land improvements
Buildings
Refineries
Petrochemicals plants
Pipelines
Service stations
Office equipment
Fixtures and fittings
15 to 25 years
20 to 50 years
20 to 30 years
20 to 30 years
10 to 50 years
15 years
3 to 7 years
5 to 15 years
The expected useful lives of property, plant and equipment are reviewed on an annual basis and, if necessary, changes in useful lives are
accounted for prospectively.
An item of property, plant and equipment is derecognized upon disposal or when no future economic benefits are expected to arise from the
continued use of the asset. Any gain or loss arising on derecognition of the asset (calculated as the difference between the net disposal
proceeds and the carrying amount of the item) is included in the income statement in the period in which the item is derecognized.
Significant estimate: 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 191, which is unaudited. Details on BP’s proved reserves and production compliance and governance processes
are provided on page 260. The 2017 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 191.
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 based upon management's assumptions for future commodity prices 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. Changes in proved reserves, therefore, could result in a material change in those
properties' carrying values within the next financial year. See also Significant judgements and estimates: recoverability of asset carrying
values.
Information on the carrying amounts of the group’s oil and natural gas properties, together with the amounts recognized in the income
statement as depreciation, depletion and amortization is contained in Note 10 and Note 4 respectively.
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.
BP Annual Report and Form 20-F 2017
133
1. Significant accounting policies, judgements, estimates and assumptions – continued
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 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 12 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, 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 $11.6 billion on its balance sheet (2016 $11.2 billion), principally relating to the
Atlantic Richfield, Burmah Castrol, Devon Energy and Reliance transactions. In testing goodwill for impairment, the group uses the approach
described above to determine recoverable amount. If there are low oil or natural gas prices for an extended period, the group may need to
recognize goodwill impairment charges against its Upstream segment goodwill. Sensitivities relating to impairment testing of goodwill in the
Upstream segment are provided in Note 12.
Details of impairment charges and reversals recognized in the income statement are provided in Note 3 and details on the carrying amounts
of assets are shown in Note 10, Note 12 and Note 13.
Assumptions made in impairment tests in 2017 relating to discount rates, oil and gas properties and oil and gas prices are discussed below.
Changes in the economic environment or other facts and circumstances may necessitate revisions to these assumptions and could result in
a material change to the carrying values of the group's assets within the next financial year.
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 2017 the discount rate used to determine recoverable amounts
based on fair value less costs of disposal was 6% (2016 6%). The discount rate used to determine recoverable amounts based on value in
use was 9% (2016 9%). 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 (2016 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 management believe 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. Based on tests performed in 2016 and 2017, 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
The long-term price assumptions used to determine recoverable amount based on fair value less costs of disposal from 2023 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 (2016 $75
per barrel and $4/mmBtu, both in 2015 prices, from 2022 onwards). To determine recoverable amount based on value in use, the price
assumptions were inflated to 2023 but from 2023 onwards were not inflated.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
For both value-in-use and fair value less costs of disposal impairment tests, the price assumptions used for the five-year period to 2022 have
been set such that there is a gradual transition from current market prices to the long-term price assumptions as noted above, with the rate
of increase reducing in the later years.
Oil prices have firmed somewhat in the wake of the extension of OPEC and non-OPEC production cuts and the gradual adjustment in oil
inventories from elevated levels. BP's long-term assumption for oil prices is higher than recent market prices reflecting the judgement that
recent prices are not consistent with the market being able to produce sufficient oil to meet global demand sustainably in the longer term.
US gas prices have been affected by short-term volatility in winter demand although remain relatively muted. BP's long-term price
assumption for US gas is higher than recent market prices as US gas production is expected to grow strongly, supported by increased
exports of liquefied natural gas, absorbing the lowest cost resources and requiring increased investment in infrastructure.
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 a specific 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 set out below. The group derecognizes financial assets when the contractual rights to the cash flows expire or the financial asset is
transferred to a third party.
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 and when interest is recognized using the
effective interest method. This category of financial assets includes trade and other receivables.
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.
Cash equivalents
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. Cash equivalents are classified as loans
and receivables, held-to-maturity financial assets or available-for-sale financial assets.
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. In particular, judgements are required in the current oil and gas price environment relating to amounts due from
countries that are reliant on revenues from hydrocarbon-producing activities. Factors considered include the credit rating of the counterparty,
the amount and timing of anticipated future payments and any possible actions that can be taken to mitigate the risk of non-payment. See
Note 27 for information on overdue receivables.
BP Annual Report and Form 20-F 2017
135
1. Significant accounting policies, judgements, estimates and assumptions – continued
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.
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.
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.
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.
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. If the forecast transaction is no longer
expected to occur, amounts previously recognized within other comprehensive income will be immediately reclassified to the income
statement.
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1. Significant accounting policies, judgements, estimates and assumptions – continued
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 judgement and estimate: derivative contracts
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 carrying amounts of derivative assets and liabilities in the next financial year. For more
information see Note 28.
In some cases, judgement is required to determine whether contracts to buy or sell commodities meet the definition of a derivative.
Contracts to buy and sell LNG are not considered to meet the definition as they are not considered capable of being net settled and so are
accounted for on an accruals basis.
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 2.5% (2016 2%) or a
real discount rate of 0.5% (2016 0.5%), 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 17 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.
BP Annual Report and Form 20-F 2017
137
1. Significant accounting policies, judgements, estimates and assumptions – continued
Significant judgements and estimates: provisions
For information on estimates and judgements relating to the Gulf of Mexico oil spill, see Note 2.
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 are political, environmental, safety and public expectations. The timing and amounts of future cash flows
are subject to significant uncertainty and estimation is required in determining the amounts of provisions to be recognized. Any changes in
the expected future costs are reflected in both the provision and the asset.
If oil and natural gas production facilities and pipelines are sold to third parties, judgement is required to assess whether the new owner will
be unable to meet their decommissioning obligations, whether BP would then be responsible for decommissioning, and if so the extent of
that responsibility.
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 current estimates because of changes in laws and
regulations, public expectations, prices, discovery and analysis of site conditions and changes in clean-up technology.
The timing and amount of future expenditures relating to decommissioning and environmental liabilities are reviewed annually, together with
the interest rate used in discounting the cash flows. The interest rate used to determine the balance sheet obligations at the end of 2017 was
a real rate of 0.5% (2016 0.5%), which was based on long-dated US government bonds.
Further information about the group’s provisions is provided in Note 21. Changes in assumptions in relation to the group's provisions could
result in a material change in their carrying amounts within the next financial year.
As described in Note 31, the group is subject to further claims and actions for which no provisions have been recognized. 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.
138
BP Annual Report and Form 20-F 2017
1. Significant accounting policies, judgements, estimates and assumptions – continued
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 when measuring the
group's pension plan surpluses and deficits. These estimates require assumptions to be made about many uncertainties.
Pensions 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 that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels.
Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with
resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation
rate, could result in material changes to the carrying amounts of the group's pension and other post-retirement benefit obligations within the
next financial year. Any differences between these assumptions and the actual outcome will also affect future net income and net assets.
The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense and
obligation used are provided in Note 22.
Income taxes
Income tax expense represents the sum of current tax and deferred tax.
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.
Where tax treatments are uncertain, if it is considered probable that a taxation authority will accept the group's proposed tax treatment,
income taxes are recognized consistent with the group's income tax filings. If it is not considered probable, the uncertainty is reflected using
either the most likely amount or an expected value, depending on which method better predicts the resolution of the uncertainty.
BP Annual Report and Form 20-F 2017
139
1. Significant accounting policies, judgements, estimates and assumptions – continued
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 whether provisions for income taxes are required and, if so, estimation is required of the amounts that could be
payable.
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 7.
The United States Tax Cuts and Jobs Act (‘the Act’) was signed into US law on 22 December 2017 and introduces significant modifications to
income tax rates and the overall basis for determining tax payable on the foreign earnings of US group companies. Changes to current and
deferred tax have been made based on the newly enacted law which is still subject to further clarification. Estimates and assumptions have
been made where necessary to assess the impact of the Act on the group's tax balances and positions. These calculations will continue to
be refined as information and clarifications from US legislative and regulatory bodies become available. See Note 7 for further information on
the impact for the year ended 31 December 2017.
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. In December 2016 BP renewed its onshore concession in Abu Dhabi. As a result
of changes in the fiscal terms of the arrangement, the group's taxes payable relating to the concession are now principally reported as
income taxes rather than as production taxes.
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
The group adopted Disclosure Initiative: Amendments to IAS 7 ‘Statement of cash flows’ with effect from 1 January 2017. The amendments
require the disclosure of information that enables users of the financial statements to evaluate changes in liabilities arising from financing
activities, including changes arising from cash flows and non-cash changes. The amendments do not have any impact upon the primary
financial statements. See Note 25 for further information.
140
BP Annual Report and Form 20-F 2017
1. Significant accounting policies, judgements, estimates and assumptions – continued
There are no other new or amended standards or interpretations adopted during the year that have a significant impact on the financial
statements.
Not yet adopted
The following three pronouncements from the IASB will become effective for future financial reporting periods and have not been adopted by
the group in these financial statements. Each of the standards has been adopted by the EU. 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.
IFRS 9 'Financial Instruments'
IFRS 9 ‘Financial Instruments’ was issued in July 2014 and replaces IAS 39 ‘Financial Instruments: Recognition and Measurement.’ BP will
adopt IFRS 9 in the financial reporting period commencing 1 January 2018.
IFRS 9 provides a single classification and measurement approach for financial assets that reflects the business model in which they are
managed and their cash flow characteristics. Under the new standard the group’s financial assets will be classified as measured at amortised
cost, fair value through profit or loss, or fair value through other comprehensive income. For financial liabilities the existing classification and
measurement requirements of IAS 39 are largely retained. Whilst financial assets will be reclassified into the categories required by IFRS 9, the
group has not identified any significant impacts on the measurement of its financial assets and financial liabilities as a result of the
classification and measurement requirements of the new standard. However, for existing equity instruments classified as available-for-sale
investments under IAS 39, we intend to recognize fair value gains and losses in profit or loss under IFRS 9, rather than in other comprehensive
income as was the case under IAS 39. An adjustment to the 2018 opening balance sheet is expected to be made to transfer $17 million of fair
value gains net of related tax from the available-for-sale investments reserve to the profit and loss account reserve. Prospectively, fair value
gains and losses on new equity instruments may be recognized either in profit or loss or in other comprehensive income as an election on an
instrument-by-instrument basis on initial recognition.
The financial asset impairment requirements of IFRS 9 introduce a forward-looking expected credit loss model that results in earlier recognition
of credit losses than the incurred loss model of IAS 39. Given the short-term nature of the majority of its financial assets and the group’s active
management of credit risk, the group does not expect a significant impact on adoption of IFRS 9’s impairment requirements. The adjustment to
the 2018 opening balance sheet, which will reduce both the carrying amounts of financial assets and the profit and loss account reserve,
makes up the majority of the adjustment on adoption of IFRS 9 in the table below. Subsequent movements in the expected loss reserve will be
recognized in profit or loss.
The hedge accounting requirements of IFRS 9 have been simplified and are more closely aligned to an entity’s risk management strategy.
Under IFRS 9 all existing hedging relationships will qualify as continuing hedging relationships and the group also intends to apply hedge
accounting prospectively to certain of its commodity price risk management activities for which hedge accounting was not possible under IAS
39. This will have no impact on the 2018 opening balance sheet.
IFRS 9 also introduces a new way of treating fair value movements on the time value and cross currency basis spreads of certain hedging
instruments. Whereas under IAS 39 these movements were recognized in profit or loss, the group is either required, or will elect, to initially
recognize these movements within equity to the extent that they relate to the hedged item. An adjustment to the 2018 opening balance sheet
is expected to be made to transfer $37 million of losses net of related tax from the profit and loss account reserve to the costs of hedging
reserve for relevant hedging instruments existing on transition.
The expected overall impact of transition on 2018 opening net assets is summarized below.
At 31 December 2017
Adjustment on adoption of IFRS 9 net of tax and including the group's share of equity-accounted entitiesa
At 1 January 2018
$ million
Net assets
100,404
(180)
100,224
a The adjustment on adoption of IFRS 9 mainly relates to an increase in the credit reserve of financial assets in the scope of IFRS 9’s impairment requirements. IFRS 9 requires credit losses
to be recognized on an expected rather than incurred loss basis as was the case under IAS 39. The profit and loss account reserve is expected to reduce by an equivalent amount.
Other minor reserves adjustments, as described above, are expected to result in an increase to the profit and loss reserve of $54 million offset
by a reduction in the available-for-sale reserve of $17 million and creation of the costs of hedging reserve of $37 million.
Under IAS 39 the effective portion of the gain or loss on a cash flow hedging instrument is reported in other comprehensive income and is
reclassified to the balance sheet as part of the initial carrying amount of the corresponding non-financial asset or liability. Under IFRS 9 the
effective portion of the gain or loss continues to be reported in the statement of other comprehensive income but the transfer to the balance
sheet will be shown in the statement of changes in equity.
IFRS 15 ‘Revenue from Contracts with Customers’
IFRS 15 ‘Revenue from Contracts with Customers’ was issued in May 2014 and replaces IAS 18 ‘Revenue’ and certain other standards and
interpretations. IFRS 15 provides a single model of accounting for revenue arising from contracts with customers, focusing on the identification
and satisfaction of performance obligations. BP will adopt IFRS 15 in the financial reporting period commencing 1 January 2018 and has elected
to apply the 'modified retrospective' transition approach to implementation.
Under IFRS 15, revenue from contracts with customers is recognized when or as the group satisfies a performance obligation by transferring a
promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The
transfer of control of oil, natural gas, natural gas liquids, LNG, petroleum and chemical products, and other items sold by the group usually
coincides with title passing to the customer and the customer taking physical possession. The group principally satisfies its performance
obligations at a point in time and the amounts of revenue recognized relating to performance obligations satisfied over time are not significant.
The accounting for revenue under IFRS 15 does not, therefore, represent a substantive change from the group’s current practice for
recognizing revenue from sales to customers.
Certain changes in accounting arising from the implementation of IFRS 15 have been identified but the new standard has had no material
effect on the group’s net assets as at 1 January 2018 and so no transition adjustment will be presented.
The most significant change identified is the accounting for revenues relating to oil and natural gas properties in which the group has an
interest with joint operation partners. From 1 January 2018, BP ceased recognizing revenue in relation to the group's entitlement to the
production from oil and gas properties based on its working interest, irrespective of whether the production was taken and sold to customers.
BP Annual Report and Form 20-F 2017
141
1. Significant accounting policies, judgements, estimates and assumptions – continued
In its 2018 financial statements the group will recognize revenue when sales are made to customers and production costs will be accrued or
deferred to reflect differences between volumes taken and sold to customers and the group's ownership interest in total production volumes.
This may result in changes in revenues and profits recognized in each period, but there will be no change in the total revenues and profits over
the duration of the joint operation. Variability in oil and gas prices and the timing of when each partner in a joint operation takes its share of
production mean that the precise impact on the group's revenues and profits in any particular future period is uncertain. However, the impact
on the group's reported net assets as at 31 December 2017 and its reported profit for the year ended 31 December 2017 of applying this
accounting would not have been material.
IFRS 15 requires the disclosure of revenue from contracts with customers disaggregated into categories that depict how the nature, amount,
timing and uncertainty of revenue and cash flows are affected by economic factors. It is the group’s intention to provide additional disclosure of
revenue from contracts with customers disaggregated by product grouping. The group’s sales and other operating revenues as reported for
2016 and 2017 by product grouping are presented below:
Crude oil
Oil products
Natural gas and NGLs
Non-oil products and other operating revenues from contracts with customers
Revenue from contracts with customersa
Other revenues
Sales and other operating revenuesa
2017
49,670
159,821
16,196
12,538
238,225
1,983
240,208
$ million
2016
32,284
126,465
11,337
11,487
181,573
1,435
183,008
a Amounts presented for 2016 and 2017 include revenues from the production of oil and natural gas properties in which the group has an interest with joint operation partners determined
using the entitlements method in accordance with the group's accounting policy for those periods (see Revenue above). The amounts presented do not, therefore, represent the Revenue
from contracts with customers or Sales and other operating revenues that would have been reported for those periods had IFRS 15 been applied using a fully retrospective transition
approach. The differences are not significant. No restatement of prior periods will be made in relation to this change.
IFRS 16 ‘Leases’
IFRS 16 ‘Leases’ provides a new model for lessee accounting in which all leases, other than short-term leases and leases of low-value items,
will be accounted for by the recognition on the balance sheet of a right-to-use asset and a lease liability. The subsequent amortization of the
right-to-use asset and the interest expense related to the lease liability will be recognized in profit or loss over the lease term. IFRS 16 replaces
IAS 17 ‘Leases’ and IFRIC 4 ‘Determining whether an arrangement contains a lease’ and will be effective for financial reporting periods
beginning on or after 1 January 2019.
BP will adopt IFRS 16 on 1 January 2019. An implementation project was initiated in 2016 and work is progressing including a system solution
to hold lease data and generate accounting entries. Work streams have also been initiated to cover data and processes, accounting policy
development and the impacts on key performance indicators and financial metrics.
On transition, BP intends to use the modified retrospective approach 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 with no restatement of comparative periods’
financial information.
IFRS 16 introduces a revised definition of a lease. As permitted by the standard, BP does not intend to reassess the existing population of
leases under the new definition and will only apply the new definition for the assessment of contracts entered into after the transition date.
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. In the cash flow statement
operating lease payments are currently presented within cash flows from operating activities but under IFRS 16 payments will be presented as
financing cash flows, representing repayments of debt, and as operating cash flows, representing payments of interest. Variable lease
payments that do not depend on an index or rate are not included in the lease liability and will continue to be presented as operating cash
flows.
Information on the group’s leases currently classified as operating leases, which are not recognized on the balance sheet, is presented in Note
26 and provides an indication of the magnitude of assets and liabilities that will be recognized on the balance sheet from 2019. However, the
commitments information provided in Note 26 is on an undiscounted basis whereas the amounts recognized under the new standard will be
on a discounted basis. The discount rates to be used on transition will be incremental borrowing rates as appropriate for each lease based on
factors such as the lessee legal entity, lease term and currency. Currently the range of such incremental borrowing rates applicable for the
majority of the leases for the group is 2% to 7%, with the rate primarily determined by the country of operation. There will likely be other
differences in the amounts recognized and our evaluation of the precise impacts is ongoing. In particular, we are considering the accounting for
leases of assets within joint operations within the Upstream segment. The operating lease commitments for leases within joint operations are
included on the basis of BP’s net working interest for the information provided in Note 26, irrespective of whether BP is the operator and
whether the lease has been co-signed by the joint operators or not. In certain circumstances, where BP is the operator, it may be appropriate
under IFRS 16 to recognize 100% of the future lease payments as the right-of-use asset and/or the lease liability. Similarly, it may be
appropriate under IFRS 16 to recognize no right-of-use asset or lease liability in cases where BP is not the operator and is not a signatory to the
lease. Our evaluation of this aspect is not yet complete. This could materially affect the amounts recognized relating to leases of drilling rigs for
which BP's share of operating lease commitments at 31 December 2017 amounted to $2,088 million on an undiscounted basis.
142
BP Annual Report and Form 20-F 2017
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.
The impacts of the Gulf of Mexico oil spill on the income statement, balance sheet and cash flow statement of the group are included within
the relevant line items in those statements and are shown in the table below.
Income statement
Production and manufacturing expenses
Profit (loss) before interest and taxation
Finance costs
Profit (loss) before taxation
Less: Taxation
Profit (loss) for the period
Balance sheet
Current assets
Trade and other receivables
Current liabilities
Trade and other payables
Provisions
Net current assets (liabilities)
Non-current assets
Deferred tax
Non-current liabilities
Other payables
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
2017
2016
2,687
(2,687)
493
(3,180)
(2,222)
(5,402)
6,640
(6,640)
494
(7,134)
3,105
(4,029)
252
194
(2,089)
(1,439)
(3,276)
(3,056)
(2,330)
(5,192)
2,067
2,973
(12,253)
(1,141)
3,634
(7,693)
(10,969)
(3,180)
493
2,542
(1,738)
(3,453)
(5,336)
(13,522)
(112)
5,119
(5,542)
(10,734)
(7,134)
494
4,353
(3,210)
(1,608)
(7,105)
$ million
2015
11,709
(11,709)
247
(11,956)
3,492
(8,464)
(11,956)
247
11,296
—
(732)
(1,145)
Income statement
The group income statement for 2017 includes a pre-tax charge of $3,180 million (2016 pre-tax charge of $7,134 million) in relation to the Gulf of
Mexico oil spill. The charge within production and manufacturing expenses in 2017 of $2,687 million (2016 $6,640 million) relates mainly to an
increase in the provision relating to business economic loss (BEL) and other claims associated with the Deepwater Horizon Court Supervised
Settlement Program (DHCSSP). The increase in the provision is primarily a result of significantly higher average claims determinations issued
by the DHCSSP in the fourth quarter of the year and the continuing effect of the Fifth Circuit's May 2017 opinion on the matching of revenues
with expenses when evaluating BEL claims. Finance costs of $493 million (2016 $494 million) reflect the unwinding of the discount on payables
and, for 2016, provisions. Taxation includes a charge of $3,012 million in respect of the revaluation of US deferred tax assets related to the Gulf
of Mexico oil spill following the reduction in the US federal corporate income tax rate from 35% to 21% enacted in December 2017.
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 2012 agreement with the US government to resolve all federal criminal claims arising from the incident, amounts
charged for the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states 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 cumulative pre-tax income statement charge since the incident amounts to $65.8 billion and is analysed in the table below.
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
2017
—
—
2,647
—
40
—
2,687
493
3,180
2016
—
—
6,596
—
44
—
6,640
494
7,134
$ million
Cumulative since
the incident
8,526
14,304
41,781
4,061
1,309
(5,681)
64,300
1,465
65,765
2015
5,303
—
5,758
551
97
—
11,709
247
11,956
BP Annual Report and Form 20-F 2017
143
2. Significant event – Gulf of Mexico oil spill – continued
Provisions and contingent liabilities
Provisions
Movements during the year in the remaining provision, which relates to litigation and claims, are presented in the table below.
At 1 January
Increase in provision
Reclassified to other payables
Utilization
At 31 December
Of which – current
– non-current
$ million
2017
Litigation and
claims
2,442
2,647
(759)
(1,750)
2,580
1,439
1,141
Litigation and claims – PSC settlement
The Economic and Property Damages Settlement Agreement (EPD Settlement Agreement) with the Plaintiffs' Steering Committee (PSC)
provides for a court-supervised settlement programme, the DHCSSP, which commenced operation on 4 June 2012. A separate claims
administrator was 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 270.
The litigation and claims provision reflects the latest estimate for the remaining costs associated with the PSC settlement. These costs relate
predominantly to BEL claims and associated administration costs. The amounts ultimately payable may differ from the amount provided and
the timing of payments is uncertain.
The increase in the provision in the year is primarily a result of significantly higher average BEL claims determinations issued by the DHCSSP
during the fourth quarter of the year and the effect of the May 2017 Fifth Circuit opinion on the policy addressing the matching of revenue with
expenses in relation to BEL claims. See Legal proceedings on page 270 for further details on the May 2017 Fifth Circuit opinion and related
appeals.
The DHCSSP’s determination of BEL claims was substantially completed by the end of 2017. Nevertheless, a significant number of BEL claims
determined by the DHCSSP have been and continue to be appealed by BP and/or the claimants, with the total value of claims under appeal or
eligible for appeal approximately doubling during the fourth quarter of the year. The DHCSSP has reported that the total determinations for all
economic and property damages claims amounted to $14.2 billion and the total amount paid with respect to such claims was $11.2 billion, in
each case as at 31 December 2017. The difference in the above DHCSSP amounts primarily relates to determinations of BEL claims under
appeal or eligible for appeal, along with certain other items, including claims determined eligible for payment and which are not being appealed.
The amount provided for includes the latest estimate of the amounts that are expected ultimately to be paid to resolve outstanding BEL claims.
Claims under appeal will ultimately only be resolved once the full judicial appeals process has been concluded, including appeals to the Federal
District Court and Fifth Circuit, as may be the case, or when settlements are reached with individual claimants. Depending upon the ultimate
resolution of these claims (including how such resolution may be impacted by the May 2017 Fifth Circuit opinion), the amounts payable may
differ from those currently provided.
The DHCSSP is expected to issue determinations with respect to remaining BEL claims in the first half of 2018. Whilst BP has a better
understanding of the total population of remaining claims, there is uncertainty around how these claims will ultimately be determined,
including in relation to the impact of the May 2017 Fifth Circuit opinion on the determination of such claims.
Payments to resolve outstanding claims under the PSC settlement are now expected to be made over a number of years. The timing of
payments, however, is uncertain, and, in particular, will be impacted by how long it takes to resolve claims that have been appealed and may be
appealed in the future.
Contingent liabilities
For information on legal proceedings relating to the Deepwater Horizon oil spill, see Legal proceedings on pages 270-273. Any further
outstanding Deepwater Horizon related claims are not expected to have a material impact on the group's financial performance.
Other payables
Other payables include amounts payable under the 2016 consent decree and settlement agreement with the United States and five Gulf coast
states, including amounts payable for natural resource damages, state claims and Clean Water Act penalties. On a discounted basis the
amounts included in other payables for these elements of the agreements are $5,556 million, $2,841 million and $4,047 million respectively at
31 December 2017. For full details of these agreements, see BP Annual Report and Form 20-F 2015.
In addition, other payables at 31 December 2017 also includes $1,209 million in relation to the 2012 agreement with the US government to
resolve all federal criminal claims arising from the incident, which falls due in 2018.
Cash flow statement
The impact on net cash provided by operating activities on a pre-tax basis amounted to an outflow of $5,336 million (2016 outflow of $7,105
million, 2015 outflow of $1,145 million). On a post-tax basis, the amounts were an outflow of $5,167 million (2016 outflow of $6,892 million and
2015 outflow of $1,130 million).
Cash outflows in 2016 and 2017 include payments made under the 2012 agreement with the US government to resolve all federal criminal
claims arising from the incident and the 2016 consent decree and settlement agreement with the United States and the five Gulf coast states.
144
BP Annual Report and Form 20-F 2017
3. Disposals and impairment
The following amounts were recognized in the income statement in respect of disposals and impairments.
Gains on sale of businesses and fixed assets
Upstream
Downstream
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
2017
2016
526
674
10
1,210
557
561
14
1,132
2017
2016
127
88
—
215
1,138
69
32
1,239
(176)
(62)
(238)
1,216
2017
2,936
478
3,414
1,183
2,078
153
3,414
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
$ million
2015
324
316
26
666
$ million
2015
124
98
41
263
2,484
265
155
2,904
(1,080)
(178)
(1,258)
1,909
$ million
2015
1,066
1,726
2,792
769
1,747
276
2,792
At 31 December 2017, deferred consideration relating to disposals amounted to $259 million receivable within one year (2016 $255 million and
2015 $41 million) and $268 million receivable after one year (2016 $271 million and 2015 $385 million). In addition, contingent consideration
receivable relating to the disposals amounted to $237 million at 31 December 2017 (2016 $131 million and 2015 $292 million).
Upstream
In 2017, gains principally resulted from the disposal of a portion of our interest in the Perdido offshore hub in the US, and further gains
associated with disposals in the UK.
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.
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.
Downstream
In 2017, gains principally resulted from the disposal of our interest in the SECCO joint venture and the disposal of certain midstream assets in
Europe.
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.
BP Annual Report and Form 20-F 2017
145
3. Disposals and impairment – continued
Summarized financial information relating to the sale of businesses is shown in the table below. The principal transaction categorized as a
business disposal in 2017 was the disposal of our interest in the Forties Pipeline System in the North Sea. 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 interests in the Central Area Transmission System in the North Sea and in the UTA European fuel cards 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
2017
735
57
(173)
(86)
533
—
3
536
44
580
(216)
121
485
(7)
478
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
$ million
2015
154
80
(70)
(50)
114
16
8
138
446
584
—
1,116
1,700
26
1,726
a 2016 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 2016 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 $25 million (2016 $676 million and 2015 $9 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. See also Note 10,
Note 13 and Note 19 for further information on impairments by asset category.
Upstream
Impairment losses and reversals related primarily to producing and midstream assets.
The 2017 impairment losses of $1,138 million related to a number of different assets, with the most significant charges arising in Lower 48 and
the North Sea. Impairment losses within Upstream arose primarily as a result of changes in reserves estimates and the decision to dispose of
certain assets, including the Forties Pipeline System business.
The 2017 impairment reversals of $176 million related to a number of different assets, with the most significant reversals arising in the North
Sea.
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.
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 6). 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.
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.
Downstream
Impairment losses totalling $69 million, $84 million, and $265 million were recognized in 2017, 2016 and 2015 respectively. The amount for 2015
was 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.
Other businesses and corporate
Impairment losses totalling $32 million, $11 million, and $155 million were recognized in 2017, 2016 and 2015 respectively. The amount for 2015
was principally in respect of our US wind business.
146
BP Annual Report and Form 20-F 2017
4. Segmental analysis
The group’s organizational structure reflects the various activities in which BP is engaged. At 31 December 2017, 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 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.
BP Annual Report and Form 20-F 2017
147
(212)
—
(212)
—
—
—
—
—
8,621
853
9,474
(2,074)
(220)
7,180
5,571
10,013
3,426
24,985
17,452
$ million
2016
Total
group
4. Segmental analysis – continued
By business
Upstream
Downstream
Rosneft
Other
businesses
and
corporate
Consolidation
adjustment
and
eliminations
$ million
2017
Total
group
1,469
(26,554)
240,208
26,554
—
—
—
240,208
2,507
45,440
219,853
(24,179)
(1,800)
21,261
218,053
—
—
—
930
674
922
5,221
8
5,229
7,221
758
7,979
836
87
923
(575)
894
(19)
(4,445)
—
(4,445)
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
4,631
8,637
220
12,093
14,500
875
1,141
304
2,349
2,677
—
—
—
10,059
—
65
235
2,902
484
275
a See explanation of inventory holding gains and losses on page 147.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
By business
Upstream
Downstream
Rosneft
Other
businesses and
corporate
Consolidation
adjustment and
eliminations
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
33,188
167,683
(17,581)
(1,291)
15,607
166,392
—
—
—
723
608
647
574
60
634
5,162
1,484
6,646
590
53
643
4,396
7,835
352
10,968
17,879
856
1,094
758
3,035
3,109
—
—
—
8,243
—
1,667
(19,530)
183,008
(658)
1,009
(18)
(8,157)
—
(8,157)
71
253
6,719
455
216
19,530
—
—
—
183,008
1,960
(196)
—
(196)
—
—
—
—
—
(2,027)
1,597
(430)
(1,675)
(190)
(2,295)
5,323
9,182
7,829
22,701
21,204
a See explanation of inventory holding gains and losses on page 147.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
148
BP Annual Report and Form 20-F 2017
4. Segmental analysis – continued
By business
Upstream
Downstream
Rosneft
Other
businesses and
corporate
Consolidation
adjustment and
eliminations
$ million
2015
Total
group
2,048
(22,958)
222,894
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
43,235
200,569
(21,949)
(68)
21,286
200,501
—
—
—
192
491
1,330
(941)
1,107
(202)
(937)
(30)
(967)
7,111
(1,863)
5,248
1,310
4
1,314
(13,477)
—
(13,477)
22,958
—
—
(36)
—
(36)
4,007
8,866
824
8,304
17,635
906
1,162
611
3,214
2,130
—
—
—
5,797
—
77
201
11,781
519
315
—
—
—
—
—
a See explanation of inventory holding gains and losses on page 147.
b Includes additions to property, plant and equipment; goodwill; intangible assets; investments in joint ventures; and investments in associates.
—
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
$ million
2017
Total
By geographical area
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Results
Replacement cost profit (loss) before interest and taxation
Non-current assets
Non-current assetsb c
US
Non-US
83,269
156,939
240,208
52
1,723
1,775
(266)
8,887
8,621
61,828
123,646
185,474
a Non-US region includes UK $48,837 million.
b Non-US region includes UK $18,004 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
Replacement cost profit (loss) before interest and taxation
Non-current assets
Non-current assetsb c
US
Non-US
$ million
2016
Total
65,132
117,876
183,008
155
528
683
(8,311)
6,284
(2,027)
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.
BP Annual Report and Form 20-F 2017
149
4. Segmental analysis – continued
By geographical area
Revenues
Third party sales and other operating revenuesa
Other income statement items
Production and similar taxes
Results
Replacement cost profit (loss) before interest and taxation
Non-current assets
Non-current assetsb c
US
Non-US
$ million
2015
Total
74,162
148,732
222,894
215
821
1,036
(12,243)
6,214
(6,029)
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.
5. 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 2.25% (2016 1.81% and 2015 1.75%)b
Unwinding of discount on provisions and other payables
2017
288
369
657
83
391
1,718
(297)
653
2,074
2016
183
323
506
698
400
1,221
(244)
698
1,675
$ million
2015
226
385
611
8
418
1,065
(179)
461
1,347
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 $64 million (2016 $56 million and 2015 $42 million).
6. Exploration for and evaluation of oil and natural gas resources
The following financial information represents the amounts included within the group totals relating to activity associated with the exploration
for and evaluation of oil and natural gas resources. All such activity is recorded within the Upstream segment.
For information on significant 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
2017
2016
1,603
477
2,080
—
17,026
82
16,944
477
1,901
1,274
447
1,721
62
16,960
102
16,858
447
2,920
$ million
2015
1,829
524
2,353
—
17,286
145
17,141
524
1,216
a 2017 includes a write-off in Angola of $574 million in relation to licence relinquishment, and Egypt of $208 million following a determination that no commercial hydrocarbons had been found.
2017 also includes a $145-million write-off in relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream
assets from Devon Energy in 2011. 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. For further information see Upstream – Exploration on page 29.
The carrying amount, by location, of exploration and appraisal expenditure capitalized as intangible assets at 31 December 2017 is shown in the
table below.
Carrying amount
$1 - 2 billion
$2 - 3 billion
Angola; India; Egypt; Middle East
US - Gulf of Mexico; Canada; Brazil
Location
150
BP Annual Report and Form 20-F 2017
7. Taxation
Tax on profit
Current tax
Charge for the year
Adjustment in respect of prior yearsa
Deferred taxb
Origination and reversal of temporary differences in the current year
Adjustment in respect of prior yearsc
Tax charge (credit) on profit or loss
2017
2016
4,208
58
4,266
(503)
(51)
(554)
3,712
1,762
(123)
1,639
(3,709)
(397)
(4,106)
(2,467)
$ million
2015
1,910
(329)
1,581
(5,090)
338
(4,752)
(3,171)
a The adjustments in respect of prior years reflect the reassessment of the current tax balances for prior years in light of changes in facts and circumstances during the year.
b Origination and reversal of temporary differences in the current year include the impact of tax rate changes on deferred tax balances. 2017 includes a charge of $859 million in respect of the
reduction in the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018; this has been calculated as the change in deferred tax balances at 31 December
2017, excluding the increase in the provision in the fourth quarter for business economic loss and other claims associated with the Deepwater Horizon Court Supervised Settlement Program
(DHCSSP). The adjustments in respect of prior periods reflect the reassessment of deferred tax balances for prior years in light of all other changes in facts and circumstances during the
year.
c 2016 included the reassessment of the recognition of deferred tax assets in relation to foreign tax credits in the US.
In 2017, the total tax charge recognized within other comprehensive income was $1,499 million (2016 $752 million credit and 2015 $1,140
million charge), primarily comprising the deferred tax impact of the remeasurements of the net pension and other post-retirement benefit
liability or asset. See Note 30 for further information.
The total tax charge recognized directly in equity was $263 million (2016 $5 million credit and 2015 $9 million charge); for 2017 this relates to
current tax on transactions with non-controlling interests.
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.
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
Deferred tax not recognized
Tax incentives for investmentb
Gulf of Mexico oil spill non-deductible costs
Disposal impactsc
Foreign exchange
Items not deductible for tax purposes
Impact of US tax reformd
Decrease in rate of UK supplementary chargee
Otherb
Effective tax rate
2016
excluding
impacts of
Gulf of
Mexico oil
spill and
impairments
2016
impacts of
Gulf of
Mexico oil
spill and
impairments
2015
excluding
impacts of
Gulf of
Mexico oil
spill and
impairments
2015
impacts of
Gulf of
Mexico oil
spill and
impairments
2016
2,914
(117)
(4)%
(5,209)
(2,350)
(2,295)
(2,467)
45% 107%
4,031
945
23%
(13,602)
(4,116)
30%
2017
7,180
3,712
52%
$ million
2015
(9,571)
(3,171)
33%
% of profit or loss before taxation
44
(7)
—
9
(6)
1
(1)
(4)
5
12
—
(1)
52
18
(15)
5
26
(9)
—
(24)
1
8
—
(15)
1
(4)
33
—
13
3
—
(2)
—
—
—
—
—
(2)
45
52
19
23
(27)
11
(4)
30
(2)
(11 )
—
19
(3)
107
17
(7)
1
17
(10)
—
(3)
18
10
—
(23)
3
23
38
—
—
(5)
—
(2)
—
—
—
—
—
(1)
30
46
3
—
(14)
4
(3)
1
(8)
(4)
—
10
(2)
33
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 A minor amendment has been made to 2015 to conform with current year presentation. There is no impact on 2016.
c In 2016 this related primarily to the tax impact on the contribution of BP’s Norwegian upstream business into Aker BP ASA.
d Relates to the deferred tax impact of the reduction in the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018.
e Relates to the deferred tax impact of the reductions in the UK supplementary charge rate applicable to profits arising in the North Sea from 20% to 10% in 2016 and from 32% to 20% in
2015.
BP Annual Report and Form 20-F 2017
151
7. Taxation – continued
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
2017
2,497
12
(554)
1,503
1
54
3,513
$ million
2016
8,054
(71)
(4,106)
(714)
(5)
(661)
2,497
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 creditsb
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 statementa
$ million
Balance sheeta
2017
2016
2015
2017
2016
(3,971)
(12)
(27)
(64)
(4,074)
340
3,503
(50)
1,476
(964)
(785)
3,520
(554)
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)
23,045
1,319
623
1,317
26,304
(1,386)
(8,618)
(672)
(3,750)
(6,493)
(1,872)
(22,791)
3,513
7,982
4,469
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
a The 2017 income statement and balance sheet are impacted by the reduction in US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018.
b The 2016 income statement reflected the impact of a loss carry-back claim in the US, displacing foreign tax credits utilized in prior periods which are now carried forward.
The recognition of deferred tax assets of $3,503 million (2016 $3,839 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. For 2017,
$2,067 million relates to the US (2016 $2,974 million) and $1,336 million relates to India (2016 $699 million).
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
2017
6.8
4.5
20.1
16.3
3.8
31.4
1.6
$ billion
2016
9.6
5.2
19.2
17.1
2.0
26.7
3.1
a These losses expire in the period 2018-2037 with applicable tax rates ranging from 3% 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 2018-2027.
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 tax charge
Current tax benefit relating to the utilization of previously unrecognized deferred tax assets
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 deferred tax assetsa
Deferred tax expense arising from the write-down of a previously recognized deferred tax asset
a 2017 includes the reassessment of prior year deferred tax balances in India in light of changes in facts and circumstances during the year.
2017
22
—
436
78
2016
40
269
394
55
$ million
2015
123
—
—
768
152
BP Annual Report and Form 20-F 2017
8. Dividends
The quarterly dividend paid on 29 March 2018 in respect of the fourth quarter 2017 was 10 cents per ordinary share ($0.60 per American
Depositary Share (ADS)). The corresponding amount in sterling was announced on 19 March 2018. 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
2017
2016
2015
2017
2016
2015
2017
2016
$ million
2015
Dividends announced and paid in cash
Preference shares
Ordinary shares
March
June
September
December
Dividend announced, paid in March
2018
8.1587
7.7563
7.6213
7.4435
30.9798
7.0125
6.9167
7.5578
7.9313
29.4183
6.6699
6.5295
6.5488
6.6342
26.3824
10.00
10.00
10.00
10.00
40.00
10.00
10.00
10.00
10.00
40.00
10.00
10.00
10.00
10.00
40.00
10.00
The details of the scrip dividends issued are shown in the table below.
Number of shares issued (thousand)
Value of shares issued ($ million)
1
1
2
1,099
1,168
1,161
1,182
4,611
1,708
1,691
1,717
1,541
6,659
1,303
1,546
1,676
1,627
6,153
1,828
2017
2016
2015
289,789
1,714
548,005
2,858
102,810
642
The financial statements for the year ended 31 December 2017 do not reflect the dividend announced on 6 February 2018 and paid in March
2018; this will be treated as an appropriation of profit in the year ending 31 December 2018.
9. Earnings per share
Per ordinary share
Basic earnings per share
Diluted earnings per share
Per American Depositary Share (ADS)
Basic earnings per share
Diluted earnings per share
2017
17.20
17.10
2017
1.03
1.03
2016
0.61
0.60
2016
0.04
0.04
Cents per share
2015
(35.39)
(35.39)
Dollars per share
2015
(2.12)
(2.12)
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).
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. 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 diluted earnings per share
2017
3,389
1
3,388
2016
115
1
114
$ million
2015
(6,482)
2
(6,484)
2017
2016
2015
19,692,613
18,744,800
18,323,646
Shares thousand
123,829
110,519
—
19,816,442
18,855,319
18,323,646
2017
2016
2015
3,282,102
3,124,133
3,053,941
Shares thousand
20,638
18,420
—
3,302,740
3,142,553
3,053,941
BP Annual Report and Form 20-F 2017
153
9. Earnings per share – continued
The number of ordinary shares outstanding at 31 December 2017, excluding treasury shares, and including certain shares that will be issuable
in the future under employee share-based payment plans was 19,817,325,868. Between 31 December 2017 and 8 March 2018, the latest
practicable date before the completion of these financial statements, there was a net increase of 61,262,729 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 90-112.
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
2017
Number of optionsab
thousand
22,399
1,112
5,145
Weighted average
exercise price $
4.34
4.46
n/a
Number of optionsab
thousand
26,284
498
3,380
2016
Weighted average
exercise price $
3.85
4.59
n/a
a Numbers of options shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
b At 31 December 2017 the quoted market price of one BP ordinary share was £5.23 (2016 £5.10).
In addition, the group operates a number of equity-settled employee share plans under which share units are granted to the group’s senior
leaders and certain other employees. These plans typically have a three-year performance or restricted period during which the units accrue net
notional dividends which are treated as having been reinvested. Leaving employment will normally preclude the conversion of units into
shares, but special arrangements apply for participants that leave for qualifying reasons. The number of shares that are expected to vest each
year under employee share plans are shown in the table below. The dilutive effect of the employee share plans at 31 December is also shown.
Share plans
Vesting
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
Over 4 years
Dilutive effect
2017
2016
Number of sharesa
Number of sharesa
thousand
101,550
108,373
85,878
413
166
296,380
126,122
thousand
92,529
94,760
102,342
680
319
290,630
113,012
a Numbers of shares shown are ordinary share equivalents (one ADS is equivalent to six ordinary shares).
There has been a net decrease of 34,787,890 in the number of potential ordinary shares relating to employee share-based payment plans
between 31 December 2017 and 8 March 2018.
154
BP Annual Report and Form 20-F 2017
10. Property, plant and equipment
Cost
At 1 January 2017
Exchange adjustments
Additions
Acquisitions
Transfers
Deletions
At 31 December 2017
Depreciation
At 1 January 2017
Exchange adjustments
Charge for the year
Impairment losses
Impairment reversals
Deletions
At 31 December 2017
Net book amount at 31
December 2017
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
Land and land
improvements
Buildings
Oil and gas
propertiesa
Plant,
machinery
and
equipment
Fittings,
fixtures and
office
equipment Transportation
Oil depots,
storage tanks
and service
stations
3,066
264
264
—
—
(120)
3,474
584
33
90
3
—
(27)
683
2,235
42
94
—
—
(798)
1,573
1,062
27
94
35
—
(400)
818
215,564
—
12,366
—
451
(2,327)
226,054
122,428
—
12,385
624
(135)
(1,976)
133,326
43,725
1,251
1,890
41
—
(245)
46,662
18,686
647
1,764
35
—
(136)
20,996
2,670
91
240
—
—
(148)
2,853
2,022
67
185
—
—
(138)
2,136
14,000
28
347
228
—
(3,829)
10,774
9,823
19
381
479
(72)
(3,107)
7,523
7,623
772
575
1
—
(223)
8,748
4,521
466
350
17
—
(169)
5,185
$ million
Total
288,883
2,448
15,776
270
451
(7,690)
300,138
159,126
1,259
15,249
1,193
(207)
(5,953)
170,667
2,791
755
92,728
25,666
717
3,251
3,563
129,471
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
8,418
(375)
568
—
—
—
(988)
7,623
5,140
(218)
384
—
4
(4)
—
(785)
4,521
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
Assets held under finance leases at net book
amount included above
At 31 December 2017
At 31 December 2016
Assets under construction included above
At 31 December 2017
At 31 December 2016
—
—
2
2
16
21
238
266
—
—
233
241
7
—
496
530
23,789
29,177
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.
11. Capital commitments
Authorized future capital expenditure for property, plant and equipment by group companies for which contracts had been signed at
31 December 2017 amounted to $11,340 million (2016 $11,207 million). BP’s share of capital commitments of joint ventures amounted to $483
million (2016 $522 million).
BP Annual Report and Form 20-F 2017
155
12. 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
2017
11,805
336
83
(61)
12,163
611
1
—
612
11,551
11,194
2017
7,728
3,758
65
11,551
$ million
2016
12,236
(544)
247
(134)
11,805
609
5
(3)
611
11,194
11,627
$ million
2016
7,726
3,401
67
11,194
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,
intangible assets and goodwill within Note 1.
Upstream
Goodwill
Excess of recoverable amount over carrying amount
2017
7,728
27,705
$ million
2016
7,726
26,035
Consistent with the prior year the review for impairment was carried out during the third quarter. As permitted by IAS 36, the detailed
calculations of recoverable amount performed in 2016 were used in the 2017 impairment test as the criteria in that standard were considered
satisfied: the headroom was substantial in 2016; 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 table above shows the carrying amount of goodwill
for the segment at year-end and the excess of the recoverable amount over the carrying amount at the date of the test (the headroom). The
recoverable amount for 2017 is based upon the remaining future cash flows from the 2016 detailed calculation. The headroom presented for
2017 does not represent the headroom that would result if a test was run based on discounted future cash flows estimated using updated
2017 data and assumptions.
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, 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. Exploration and
appraisal assets are deemed to have a recoverable amount equal to their carrying amount.
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. The price and discount rate assumptions for 2016 were used as disclosed in Note 1. The fair value less costs of disposal calculations were
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 prior year 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.
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BP Annual Report and Form 20-F 2017
12. Goodwill and impairment review of goodwill – continued
The sensitivities to different variables were estimated for 2016 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.
For 2016 it is estimated that if the oil price assumption for all future years 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. For 2016, the average production for the purposes of goodwill impairment testing over the following 15
years is 889mmboe per year and 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.
For 2016 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
2,849
Other
909
2017
Total
3,758
Lubricants
2,571
Other
830
$ million
2016
Total
3,401
Cash flows for each cash-generating unit are derived from the business segment plans, which cover a period of up 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 2017 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 is 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.
13. Intangible assets
Cost
At 1 January
Exchange adjustments
Acquisitions
Additions
Transfers
Deletions
At 31 December
Amortization
At 1 January
Exchange adjustments
Charge for the year
Impairment losses
Transfers
Deletions
At 31 December
Net book amount at 31 December
Net book amount at 1 January
a For further information see Intangible assets within Note 1 and Note 6.
Exploration
and appraisal
expenditurea
Other
intangibles
18,524
—
—
2,128
(451)
(2,315)
17,886
1,564
—
1,603
—
—
(2,307)
860
17,026
16,960
4,035
197
41
310
—
(95)
4,488
2,812
107
335
—
—
(95)
3,159
1,329
1,223
2017
Total
22,559
197
41
2,438
(451)
(2,410)
22,374
4,376
107
1,938
—
—
(2,402)
4,019
18,355
18,183
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
$ million
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
BP Annual Report and Form 20-F 2017
157
14. Investments in joint ventures
The following table provides aggregated summarized financial information relating to the group’s share of joint ventures.
Sales and other operating revenues
Profit before interest and taxation
Finance costs
Profit before taxation
Taxation
Profit (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
2015a
9,588
785
188
597
625
(28)
(1)
(29)
2017
11,380
1,394
100
1,294
117
1,177
8
1,185
10,139
2,419
12,558
1,687
2,927
4,614
7,944
7,944
50
7,994
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
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.
In December 2017, BP completed a cash-free transaction with Bridas Corporation (Bridas) in which its interests in the oil and gas producer Pan
American Energy (PAE) and Bridas’ interest in the refiner and marketer Axion Energy (Axion) were combined to form a new integrated energy
company. PAE was previously owned 60% by BP and 40% by Bridas. The new company, Pan American Energy Group, is owned equally by BP
and Bridas.
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
Sales
2,929
2017
Amount
receivable at
31 December
352
2017
Sales
2,760
2016
Amount
receivable at
31 December
291
2016
Sales
2,841
Amount
payable at
31 December
Purchases
Amount
payable at
31 December
Purchases
Purchases
$ million
2015
Amount
receivable at
31 December
245
$ million
2015
Amount
payable at
31 December
1,257
176
943
120
861
104
The terms of the outstanding balances receivable from joint ventures are typically 30 to 45 days. The balances are unsecured and will be
settled in cash. There are no significant provisions for doubtful debts relating to these balances and no significant expense recognized in the
income statement in respect of bad or doubtful debts. Dividends receivable are not included in the table above.
15. Investments in associates
The following table provides aggregated summarized financial information for the group’s associates as it relates to the amounts recognized in
the group income statement and on the group balance sheet.
Rosneft
Other associates
Income statement
Earnings from associates
- after interest and tax
2017
922
408
1,330
2016
647
347
994
2015
1,330
509
1,839
2017
10,059
6,932
16,991
$ million
Balance sheet
Investments in
associates
2016
8,243
5,849
14,092
The associate that is material to the group at both 31 December 2017 and 2016 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 2017.
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
currency is the Russian rouble. The increase in the group`s equity-accounted investment balance for Rosneft at 31 December 2017 compared
158
BP Annual Report and Form 20-F 2017
15. Investments in associates – continued
with 31 December 2016 principally relates to earnings from Rosneft and 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 $4.99 per share (2016 $6.50 per share) was
$10,444 million at 31 December 2017 (2016 $13,604 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 2017, 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
2015
84,071
12,253
3,696
8,557
1,792
30
6,735
(4,111)
2,624
2017
103,028
9,949
2,228
7,721
1,742
1,311
4,668
2,810
7,478
158,719
39,737
198,456
66,506
70,704
137,210
61,246
10,314
50,932
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
The group received dividends, net of withholding tax, of $314 million from Rosneft in 2017 (2016 $332 million and 2015 $271 million).
Summarized financial information for the group’s share of associates is shown below.
$ million
BP share
2015
Total
22,604
3,081
736
2,345
500
6
1,839
(814)
1,025
Rosnefta
16,604
2,420
730
1,690
354
6
1,330
(812)
518
Other
6,000
661
6
655
146
—
509
(2)
507
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
20,348
1,965
440
1,525
344
259
922
555
1,477
31,347
7,848
39,195
13,135
13,964
27,099
12,096
2,037
10,059
Other
7,600
626
54
572
164
—
408
1
409
9,261
2,645
11,906
2,501
3,308
5,809
6,097
—
6,097
2017
Total
27,948
2,591
494
2,097
508
259
1,330
556
1,886
40,608
10,493
51,101
15,636
17,272
32,908
18,193
2,037
16,156
Rosnefta
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
Other
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
10,059
6,097
16,156
8,243
5,089
13,332
—
835
835
—
760
760
10,059
6,932
16,991
8,243
5,849
14,092
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.
BP Annual Report and Form 20-F 2017
159
15. 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
Sales
2,261
2017
Amount
receivable at
31 December
216
2017
Sales
4,210
2016
Amount
receivable at
31 December
765
2016
Sales
5,302
Amount
payable at
31 December
Purchases
Amount
payable at
31 December
Purchases
Purchases
$ million
2015
Amount
receivable at
31 December
1,058
$ million
2015
Amount
payable at
31 December
Crude oil and oil products, natural gas, transportation
tariff
11,613
1,681
8,873
2,000
11,619
2,026
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 $13,932 million (2016 $15,344 million), primarily in relation to contracts with its associates for the purchase
of transportation capacity.
16. Other investments
Equity investmentsa
Other
a The majority of equity investments are unlisted.
2017
$ million
2016
Current
Non-current
Current
Non-current
15
110
125
418
827
1,245
2
42
44
405
628
1,033
Other non-current investments includes $662 million relating to life insurance policies in the US (2016 $628 million) which are financial assets
measured at fair value through profit or loss. The fair value is determined using the higher of the amount that would be received if the policies
were cashed in and discounted future cash flows that would be received on maturity of the policies. It is considered a level 3 valuation under
the fair value hierarchy. Future cash flows are estimated based on inputs that include life expectancy, investment performance and the cost of
insurance cover. The pre-tax discount rate is based on a third-party high-quality US insurance company corporate bond index.
17. Inventories
Crude oil
Natural gas
Refined petroleum and petrochemical products
Supplies
Trading inventories
Cost of inventories expensed in the income statement
2017
5,692
119
10,694
16,505
2,211
18,716
295
19,011
179,716
$ million
2016
5,531
155
9,198
14,884
2,388
17,272
383
17,655
132,219
The inventory valuation at 31 December 2017 is stated net of a provision of $474 million (2016 $501 million) to write down inventories
(principally supplies) to their net realizable value. The net credit to the income statement in the year in respect of inventory net realizable value
provisions was $27 million (2016 $769 million credit).
Trading inventories are valued using quoted benchmark 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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BP Annual Report and Form 20-F 2017
18. Trade and other receivables
Financial assets
Trade receivables
Amounts receivable from joint ventures and associates
Other receivables
Non-financial assets
Gulf of Mexico oil spill trust fund reimbursement asset
Other receivables
2017
$ million
2016
Current
Non-current
Current
Non-current
18,912
566
4,206
23,684
252
913
1,165
24,849
4
2
671
677
—
757
757
1,434
13,393
1,056
5,352
19,801
194
680
874
20,675
—
—
815
815
—
659
659
1,474
Non-recourse arrangements to discount receivables, as part of discretionary funding in support of certain supply and trading activities and
management of credit risk, included $1.7 billion relating to receivables based on provisional prices (2016 $1.3 billion). The group had continuing
involvement in these receivables to the extent of movements in market prices after the date of discounting. The amounts which continued to
be recognized on the balance sheet relating to the group’s continuing involvement in these receivables totalled $0.2 billion, unchanged from
2016.
Trade and other receivables are predominantly non-interest bearing. See Note 27 for further information.
19. Valuation and qualifying accounts
At 1 January
Charged to costs and expenses
Charged to other accountsa
Deductions
At 31 December
a Principally exchange adjustments.
2017
2016
$ million
2015
Accounts
receivable
Fixed asset
investments
Accounts
receivable
Fixed asset
investments
Accounts
receivable
Fixed asset
investments
392
68
13
(138)
335
335
47
3
(71)
314
447
120
(7)
(168)
392
435
55
(2)
(153)
335
331
243
(23)
(104)
447
517
195
(4)
(273)
435
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.
20. Trade and other payables
Financial liabilities
Trade payables
Amounts payable to joint ventures and associates
Other payablesa
Non-financial liabilities
Other payables
2017
$ million
2016
Current
Non-current
Current
Non-current
26,983
1,857
11,632
40,472
3,737
44,209
—
—
13,582
13,582
307
13,889
21,575
2,120
12,079
35,774
2,141
37,915
—
—
13,760
13,760
186
13,946
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 27 for further
information.
BP Annual Report and Form 20-F 2017
161
21. Provisions
At 1 January 2017
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 2017
Of which – current
– non-current
Of which – Gulf of Mexico oil spilla
Decommissioning
Environmental
Litigation and
claims
16,442
326
—
(228)
—
121
(106)
(21)
(239)
(195)
16,100
378
15,722
—
1,584
12
2
249
(94)
8
—
(231)
—
(14)
1,516
269
1,247
—
3,162
4
—
2,907
(26)
8
(13)
(1,916)
(792)
—
3,334
1,738
1,596
2,580
$ million
Total
24,424
504
2
3,714
(489)
150
(133)
(2,907)
(1,104)
(217)
23,944
3,324
20,620
2,580
Other
3,236
162
—
786
(369)
13
(14)
(739)
(73)
(8)
2,994
939
2,055
—
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 2017 are provisions for deferred employee compensation of $391 million (2016 $422 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.
22. Pensions and other post-retirement benefits
Most group companies have pension plans, the forms and benefits of which vary with conditions and practices in the countries concerned.
Pension benefits may be provided through defined contribution plans (money purchase schemes) or defined benefit plans (final salary and
other types of schemes with committed pension benefit payments). For defined contribution plans, retirement benefits are determined by the
value of funds arising from contributions paid in respect of each employee. For defined benefit plans, retirement benefits are based on such
factors as 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 2017 the aggregate level of contributions was $637 million (2016 $651 million and 2015 $1,066 million). The aggregate level of
contributions in 2018 is expected to be approximately $600 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 is agreed. The current agreement covers the next five years. The funding agreement can be
terminated unilaterally by either party with two years’ notice. Contractually committed funding therefore represents seven years of future
contributions, which amounted to $2,623 million at 31 December 2017, of which $106 million relates to past service.This amount is included in
the group’s committed cash flows relating to pensions and other post-retirement benefit plans as set out in the table of contractual obligations
on page 252.
162
BP Annual Report and Form 20-F 2017
22. Pensions and other post-retirement benefits – continued
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 2017 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 2017.
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 2017. 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, and a valuation as at 31 December 2017 is currently under way. A valuation of the US plan is carried out annually.
The material financial assumptions used to estimate the benefit obligations of the various plans are set out below. The assumptions are
reviewed by management at the end of each year, and are used to evaluate the accrued benefit obligation at 31 December and pension
expense for the following year.
Financial assumptions used to determine benefit
obligation
Discount rate for plan liabilities
Rate of increase in salaries
Rate of increase for pensions in
payment
Rate of increase in deferred pensions
Inflation for plan liabilities
Financial assumptions used to determine benefit
expense
Discount rate for plan service cost
Discount rate for plan other finance
expense
Inflation for plan service cost
2017
2.5
4.1
2.9
2.9
3.1
2017
2.7
2.7
3.2
2016
2.7
4.6
3.0
3.0
3.2
2016
4.0
3.9
3.1
UK
2015
3.9
4.4
3.0
3.0
3.0
UK
2015
3.9
3.6
3.1
2017
3.5
4.1
—
—
1.7
2017
4.1
3.9
1.8
2016
3.9
4.2
—
—
1.8
2016
4.2
4.0
1.5
US
2015
4.0
3.9
—
—
1.5
US
2015
3.8
3.7
1.6
2017
1.9
3.0
1.4
0.6
1.6
2017
2.1
1.7
1.6
%
Eurozone
2015
2.4
3.2
1.6
0.6
1.8
%
Eurozone
2015
2.3
2.0
2.0
2016
1.7
3.0
1.5
0.5
1.6
2016
2.7
2.4
1.8
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.
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 an 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
2017
2016
UK
2015
2017
2016
US
2015
Years
Eurozone
2017
2016
2015
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
27.4
28.0
28.5
25.1
25.7
25.7
25.1
25.0
24.9
29.0
30.0
31.0
26.8
27.5
27.5
27.6
27.6
27.5
28.8
29.5
29.5
28.4
29.3
29.2
29.0
28.9
28.8
30.5
31.9
31.9
30.0
31.0
30.9
31.4
31.3
31.2
Pension plan assets are generally held in trusts, the primary objective of which is to accumulate assets sufficient to meet the obligations of the
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.
The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way
as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the UK plan uses a liability driven investment
(LDI) approach for part of the portfolio, investing in government bonds to achieve this matching effect for the most significant plan liability
assumptions of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows
money using existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used
to invest in further bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the
analysis of pension plan assets in the table below.
BP Annual Report and Form 20-F 2017
163
22. Pensions and other post-retirement benefits – continued
For the primary UK pension plan there is an agreement with the trustee to increase the proportion of assets included in the LDI portfolio over
time by reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. There is a similar agreement in
place for the primary US plan. During 2017, the UK and the US plans switched 15% and 5% of plan assets respectively from equities to bonds.
The current asset allocation policy for the major plans at 31 December 2017 was as follows:
Asset category
Total equity (including private equity)
Bonds/cash (including LDI)
Property/real estate
UK
%
43
50
7
US
%
50
50
—
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2017 were $2,588 million (2016 $423
million) of government-issued nominal bonds and $16,177 million (2016 $9,384 million) of index-linked bonds.
In addition, the primary UK plan entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $1,333
million (2016 $4,450 million) of the corporate bond portfolio. At 31 December 2017 the fair value liability of these swaps was $49 million (2016
$144 million fair value liability) 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 165.
Fair value of pension plan assets
At 31 December 2017
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Propertyd
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
At 31 December 2016
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Propertyd
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
At 31 December 2015
Listed equities – developed markets
– emerging markets
Private equityc
Government issued nominal bonds
Government issued index-linked bonds
Corporate bonds
Propertyd
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
UKa
USb
Eurozone
Other
9,548
2,220
2,679
2,663
16,177
4,682
2,211
390
104
(5,583)
35,091
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
2,158
220
1,461
1,777
—
2,024
6
80
53
—
7,779
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
537
83
—
941
2
546
71
21
23
—
2,224
436
54
1
821
4
427
45
17
74
—
1,879
423
49
1
685
5
551
48
10
102
—
1,874
376
53
—
545
—
272
30
98
45
—
1,419
363
46
—
448
—
259
28
83
83
—
1,310
371
50
4
492
—
367
58
139
50
—
1,531
$ million
Total
12,619
2,576
4,140
5,926
16,179
7,524
2,318
589
225
(5,583)
46,513
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
a Bonds held by the UK pension plans are 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.
c Private equity is valued at fair value based on the most recent third-party net asset valuation.
d Properties are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party valuers.
164
BP Annual Report and Form 20-F 2017
22. 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
Settlementb
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 (income) 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
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
UK
US
Eurozone
Other
357
12
—
369
31
400
(845)
831
(14)
2,396
(236)
734
91
2,985
29,908
2,886
369
831
16
(1,903)
(5)
—
—
(589)
31,513
30,180
3,048
845
16
509
(1,903)
2,396
35,091
3,578
3,838
(260)
3,578
3,838
(260)
3,578
292
—
—
292
191
483
(266)
393
127
826
(514)
72
(40)
344
10,533
—
292
393
—
(641)
(239)
1
(1)
482
10,820
7,316
—
266
—
12
(641)
826
7,779
(3,041)
85
5
13
103
7
110
(37)
121
84
30
336
—
(36)
330
6,820
915
103
121
2
(75)
(302)
—
(9)
(300)
7,275
1,879
264
37
2
87
(75)
30
2,224
(5,051)
260
(3,301)
(3,041)
43
(5,094)
(5,051)
238
(3,279)
(3,041)
(106)
(4,945)
(5,051)
46
(1)
—
45
38
83
(48)
71
23
43
(47)
(23)
14
(13)
1,715
89
45
71
6
(89)
(20)
—
—
56
1,873
1,310
72
48
6
29
(89)
43
1,419
(454)
28
(482)
(454)
(101)
(353)
(454)
$ million
2017
Total
780
16
13
809
267
1,076
(1,196)
1,416
220
3,295
(461)
783
29
3,646
48,976
3,890
809
1,416
24
(2,708)
(566)
1
(10)
(351)
51,481
40,685
3,384
1,196
24
637
(2,708)
3,295
46,513
(4,968)
4,169
(9,137)
(4,968)
3,869
(8,837)
(4,968)
(31,253)
(260)
(31,513)
(7,541)
(3,279)
(10,820)
(2,330)
(4,945)
(7,275)
(1,520)
(353)
(1,873)
(42,644)
(8,837)
(51,481)
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 and settlements have arisen from restructuring programmes and represent 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 $3,235 million benefits and $2 million settlements, plus $37 million of plan expenses incurred in the administration of the benefit.
e The benefit obligation for the US is made up of $8,085 million for pension liabilities and $2,735 million for other post-retirement benefit liabilities (which are unfunded and are primarily retiree
medical liabilities). The benefit obligation for the Eurozone includes $4,586 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 164.
BP Annual Report and Form 20-F 2017
165
22. 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 (income) 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
UK
US
Eurozone
Other
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
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)
(36)
(3,181)
(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)
(316)
(4,625)
(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)
(83)
(322)
(405)
$ 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)
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 164.
166
BP Annual Report and Form 20-F 2017
22. 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
UK
US
Eurozone
Other
485
12
—
497
31
528
(1,124)
1,146
22
315
2,054
—
336
2,705
371
(27)
—
344
205
549
(289)
423
134
(139)
607
60
(48)
480
96
47
(1)
142
8
150
(37)
151
114
25
592
15
47
679
96
(7)
(3)
86
41
127
(55)
91
36
33
213
—
29
275
$ million
2015
Total
1,048
25
(4)
1,069
285
1,354
(1,505)
1,811
306
234
3,466
75
364
4,139
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.
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 2017 for the group’s plans would have had the effects shown
in the table below. The effects shown for the expense in 2018 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 2018
Effect on pension and other post-retirement benefit obligation at 31 December 2017
Inflation rateb
Effect on pension and other post-retirement benefit expense in 2018
Effect on pension and other post-retirement benefit obligation at 31 December 2017
Salary growth
Effect on pension and other post-retirement benefit expense in 2018
Effect on pension and other post-retirement benefit obligation at 31 December 2017
$ million
One percentage point
Increase
Decrease
(366)
(7,532)
241
5,373
78
837
298
9,751
(200)
(4,690)
(68)
(747)
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 2018 pension and other post-retirement benefit expense by
$56 million and the pension and other post-retirement benefit obligation at 31 December 2017 by $1,694 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 2027 and the
weighted average duration of the defined benefit obligations at 31 December 2017 are as follows:
Estimated future benefit payments
2018
2019
2020
2021
2022
2023-2027
Weighted average duration
UK
1,101
1,087
1,108
1,148
1,176
6,319
19.8
US
Eurozone
Other
847
815
798
853
784
3,701
369
359
346
336
332
1,559
109
110
109
109
112
563
9.5
14.3
13.1
$ million
Total
2,426
2,371
2,361
2,446
2,404
12,142
Years
BP Annual Report and Form 20-F 2017
167
23. Cash and cash equivalents
Cash
Term bank deposits
Cash equivalents (excluding term bank deposits)
2017
4,592
17,324
3,670
25,586
$ million
2016
5,592
15,947
1,945
23,484
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 2017 includes $1,488 million (2016 $2,059 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 $3,638 million (2016 $3,649 million) of cash and cash equivalents outside the UK and it is not expected that any significant tax
will arise on repatriation.
24. Finance debt
Borrowings
Net obligations under finance leases
Current
Non-current
7,701
38
7,739
54,873
618
55,491
2017
Total
62,574
656
63,230
Current
6,592
42
6,634
Non-current
51,074
592
51,666
$ million
2016
Total
57,666
634
58,300
The main elements of current borrowings are the current portion of long-term borrowings that is due to be repaid in the next 12 months of
$6,849 million (2016 $5,587 million) and issued commercial paper of $744 million (2016 $971 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
US dollar
Other currencies
Weighted
average
interest
rate
%
Weighted
average
time for
which rate
is fixed
Years
4
6
3
7
4
16
4
16
Weighted
average
interest
rate
%
3
3
2
1
Amount
$ million
18,090
895
18,985
8,693
809
9,502
Amount
$ million
44,212
33
44,245
47,749
1,049
48,798
Amount
$ million
2017
62,302
928
63,230
2016
56,442
1,858
58,300
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 2017, 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 of 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 analysis 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
2017
Carrying
amount
852
61,722
656
63,230
Fair value
1,006
57,723
1,097
59,826
Fair value
852
63,182
1,131
65,165
$ million
2016
Carrying
amount
1,006
56,660
634
58,300
168
BP Annual Report and Form 20-F 2017
25. Capital disclosures and analysis of changes in net debt
The group defines capital as total equity. We maintain our financial framework to support the pursuit of value growth for shareholders, while
ensuring a secure financial base.
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 and maintain a significant liquidity buffer. At 31 December 2017, the net debt ratio
was 27.4% (2016 26.8%).
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
2017
63,230
(175)
63,405
25,586
37,819
100,404
27.4 %
$ million
2016
58,300
(697)
58,997
23,484
35,513
96,843
26.8%
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 $634
million (2016 liability 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.
The movement in the year is attributable to a net cash outflow of $242 million (2016 net cash outflow $299 million) and fair value gains of $1,086 million (2016 fair value losses of $644
million).
An analysis of changes in net debt is provided below. Amendments have been made to the presentation of this analysis to eliminate
movements related to non-hedge accounted derivatives.
Movement in net debt
At 1 January
Exchange adjustments
Net financing cash flow
Fair value gains (losses)
Other movements
At 31 December
Finance
debt
(58,300)
(1,324)
(2,236)
(1,314)
(56)
(63,230)
Hedge-
accounted
derivatives
Cash and
cash
equivalents
(697)
—
(284)
1,282
(476)
(175)
23,484
544
1,558
—
—
25,586
2017
Net debt
(35,513)
(780)
(962)
(32)
(532)
(37,819)
Finance
debt
(53,168)
380
(6,363)
805
46
(58,300)
Hedge-
accounted
derivatives
Cash and
cash
equivalents
(379)
—
256
(896)
322
(697)
26,389
(820)
(2,085)
—
—
23,484
$ million
2016
Net debt
(27,158)
(440)
(8,192)
(91)
368
(35,513)
26. Operating leases
The cost recognized in relation to minimum lease payments for the year was $4,423 million (2016 $5,113 million and 2015 $6,008 million).
The future minimum lease payments at 31 December 2017, before deducting related rental income from operating sub-leases of $188 million
(2016 $186 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
2017
2,969
6,387
4,614
13,970
$ million
2016
3,315
6,651
4,289
14,255
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 ten years for leases of plant and machinery, up to fifteen years for leases of ships and
commercial vehicles and up to forty years for leases of land and buildings.
The most significant items of plant and machinery hired under operating leases are drilling rigs used in the Upstream segment. At
31 December 2017, the future minimum lease payments relating to these amounted to $2,088 million (2016 $2,969 million).
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 future minimum lease payments relating to operating leases for international oil and gas ships
managed by the BP Shipping function amounted to $3,172 million (2016 $3,582 million).
BP Annual Report and Form 20-F 2017
169
26. 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.
BP will adopt IFRS 16 'Leases' on 1 January 2019. See Note 1 for further details.
27. Financial instruments and financial risk factors
The accounting classification of each category of financial instruments, and their carrying amounts, are set out below.
At 31 December 2017
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 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
Note
Loans and
receivables
Available-
for-sale
financial
assets
Held-to-
maturity
investments
At fair value
through profit
or loss
Derivative
hedging
instruments
Financial
liabilities
measured at
amortized cost
$ million
Total carrying
amount
16
16
18
28
23
20
28
24
16
16
18
28
23
20
28
24
—
—
836
24,361
—
21,916
—
—
—
—
47,113
—
—
791
20,616
—
21,539
—
—
—
—
42,946
433
275
—
—
—
2,270
—
—
—
—
2,978
407
42
—
—
—
1,749
—
—
—
—
2,198
—
—
—
—
—
1,400
—
—
—
1,400
—
—
—
—
—
196
—
—
—
196
—
662
—
—
6,454
—
—
(5,705)
—
—
1,411
—
628
—
—
6,490
—
—
(6,507)
—
—
611
—
—
—
—
688
—
—
(864)
—
—
(176)
—
—
—
—
885
—
—
—
—
—
—
—
(54,054)
—
(5,465)
(63,230)
(122,749)
—
—
—
—
—
—
—
(1,997)
—
—
(1,112)
(49,534)
—
(5,605)
(58,300)
(113,439)
433
937
836
24,361
7,142
25,586
(54,054)
(6,569)
(5,465)
(63,230)
(70,023)
407
670
791
20,616
7,375
23,484
(49,534)
(8,504)
(5,605)
(58,300)
(68,600)
The fair value of finance debt is shown in Note 24. For all other financial instruments, the carrying amount is either the fair value, or
approximates the fair value.
Financial risk factors
The group is exposed to a number of different financial risks arising from natural business exposures as well as its use of financial instruments
including market risks relating to commodity prices, foreign currency exchange rates and interest rates; credit risk; and liquidity risk.
The group financial risk committee (GFRC) advises the group chief financial officer (CFO) who oversees the management of these risks. The
GFRC is chaired by the CFO and consists of a group of senior managers including the group treasurer and the heads of the group finance, tax
and the integrated supply and trading functions. The purpose of the committee is to advise on financial risks and the appropriate financial risk
governance framework for the group. The committee provides assurance to the CFO and the group chief executive (GCE), and via the GCE to
the board, that the group’s financial risk-taking activity is governed by appropriate policies and procedures and that financial risks are identified,
measured and managed in accordance with group policies and group risk appetite.
The group’s trading activities in the oil, natural gas, LNG and power markets are managed within the integrated supply and trading
function. Treasury holds foreign exchange and interest-rate products in the financial markets to hedge group exposures related to debt
issuance; the compliance, control, and risk management processes for these activities are managed within the treasury function. All other
foreign exchange and interest rate activities within financial markets are performed within the integrated supply and trading function and are
also underpinned by the compliance, control and risk management infrastructure common to the activities of BP’s integrated and supply
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.
170
BP Annual Report and Form 20-F 2017
27. 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
Since BP has global operations, fluctuations in foreign currency exchange rates can have a significant effect on the group’s reported results and
future expenditure commitments. 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.
Most of the group’s borrowings are in US dollars or are hedged with respect to the US dollar. At 31 December 2017, the total foreign currency
borrowings not swapped into US dollars amounted to $928 million (2016 $809 million).
The group manages the net residual foreign currency 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.
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, Norwegian krone and Korean Won. At 31 December 2017 the most significant open contracts in
place were for $437 million sterling (2016 $1,204 million sterling).
For UK, Eurozone and Australian operational requirements the group uses cylinders (purchased call and sold put options) to manage the
estimated exposures. At 31 December 2017, there are no open positions hedging these exposures (2016 cylinders consisted of receive sterling,
pay US dollar cylinders $1,885 million; receive euro, pay US dollar cylinders for $585 million; receive Australian dollar, pay US dollar cylinders for
$274 million).
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 in (i) commodity price risk above.
(iii) Interest rate risk
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. Whilst 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 2017 was 70% of
total finance debt outstanding (2016 84%). The weighted average interest rate on finance debt at 31 December 2017 was 3% (2016 2%) and
the weighted average maturity of fixed rate debt was five years (2016 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 2018, it is estimated that the group’s
finance costs for 2018 would increase by approximately $442 million (2016 $488 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 2017 was
$656 million (2016 $309 million) in respect of liabilities of joint ventures and associates and $382 million (2016 $370 million) in respect of
liabilities of other third parties.
BP Annual Report and Form 20-F 2017
171
27. 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 2017, the group had in place credit enhancements
designed to mitigate approximately $14.7 billion of credit risk (2016 $11.6 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 77% (2016 79%) 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
2017
22,858
53
637
130
114
569
24,361
$ million
2016
19,459
71
446
116
56
468
20,616
Movements in the impairment provision for trade receivables are shown in Note 19.
Financial instruments subject to offsetting, enforceable master netting arrangements and similar agreements
The following table shows the 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 2017
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
At 31 December 2016
Derivative assets
Derivative liabilities
Trade and other receivables
Trade and other payables
Gross
amounts of
recognized
financial
assets
(liabilities)
8,522
(7,818)
11,648
(12,543)
9,025
(10,236)
8,815
(9,664)
Related amounts not set off
in the balance sheet
$ million
Net amounts
presented on
the balance
sheet
Master
netting
arrangements
Cash
collateral
(received)
pledged
Net amount
7,142
(6,438)
6,337
(7,232)
7,143
(8,354)
4,347
(5,196)
(1,554)
1,554
(2,156)
2,156
(1,058)
1,058
(1,039)
1,039
(321)
—
(114)
—
(133)
—
(118)
—
5,267
(4,884)
4,067
(5,076)
5,952
(7,296)
3,190
(4,157)
Amounts
set off
(1,380)
1,380
(5,311)
5,311
(1,882)
1,882
(4,468)
4,468
(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- (stable outlook) and Moody’s Investors Service rating is A1 (positive outlook).
During 2017, $8 billion of long-term taxable bonds were issued with terms ranging from one 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 $25.6 billion at
31 December 2017 (2016 $23.5 billion), primarily invested with highly rated banks or money market funds and readily accessible at immediate
and short notice. At 31 December 2017, the group had substantial amounts of undrawn borrowing facilities available, consisting of $7,625
million of standby facilities, all of which is available to draw and repay up to the first half of 2022. These facilities are with 25 international
banks, and borrowings under them would be at pre-agreed rates.
The group also has committed letter of credit (LC) facilities totalling $9,400 million with a number of banks, allowing LCs to be issued for a
maximum 23-month duration. There were also uncommitted secured LC facilities in place at 31 December 2017 for $1,560 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.
172
BP Annual Report and Form 20-F 2017
27. Financial instruments and financial risk factors – continued
The amounts shown for finance debt in the table below include future minimum lease payments with respect to finance leases. The table also
shows the timing of cash outflows relating to trade and other payables and accruals.
Within one year
1 to 2 years
2 to 3 years
3 to 4 years
4 to 5 years
5 to 10 years
Over 10 years
Trade and
other
payablesa
40,472
1,693
1,413
1,378
1,368
6,181
6,125
58,630
Accruals
4,960
135
83
70
54
115
48
5,465
2017
Interest on
finance debt
1,757
1,537
1,321
1,114
894
1,951
390
8,964
Finance
debtb
7,626
7,331
7,068
6,766
7,986
24,162
2,089
63,028
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
$ million
2016
Interest on
finance debtc
1,217
1,083
942
801
658
1,446
382
6,529
Finance
debtb
6,620
5,909
6,624
6,201
6,564
22,190
3,573
57,681
a 2017 includes $18,918 million (2016 $21,644 million) in relation to the Gulf of Mexico oil spill.
b Fair value adjustments relating to hedging activity have been excluded from finance debt which therefore is not equal the amounts presented on the balance sheet. 2016 has been amended
to conform with this presentation.
c 2016 has been amended to exclude interest payments that do not relate to finance debt. Interest on liabilities is included in trade and other payables.
The group manages liquidity risk associated with derivative contracts, other than derivative hedging instruments, based on the expected
maturities of both derivative assets and liabilities as indicated in Note 28. Management does not currently anticipate any cash flows that could
be of a significantly different amount, or could occur earlier than the expected maturity analysis provided.
The table below shows 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 $21,484 million at 31 December 2017 (2016 $18,014
million) to be received on the same day as the related cash outflows. For further information on our derivative financial instruments, see Note
28.
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
2017
1,505
1,700
1,678
2,384
2,838
11,238
724
22,067
$ million
2016
2,677
1,505
1,700
1,678
2,384
9,985
1,413
21,342
28. Derivative financial instruments
In the normal course of business the group enters into derivative financial instruments (derivatives) to manage its normal business exposures
in relation to commodity prices, foreign currency exchange rates and interest rates, including management of the balance between floating
rate and fixed rate debt, consistent with risk management policies and objectives. An outline of the group’s financial risks and the objectives
and policies pursued in relation to those risks is set out in Note 27. Additionally, the group has a well-established entrepreneurial trading
operation that is undertaken in conjunction with these activities using a similar range of contracts.
For information on significant estimates and judgements made in relation to the 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.
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.
BP Annual Report and Form 20-F 2017
173
28. Derivative financial instruments – continued
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
2017
Fair value
liability
237
1,637
3,580
885
115
6,454
—
—
—
35
—
35
460
193
653
7,142
3,032
4,110
(756)
(1,281)
(2,844)
(693)
—
(5,574)
(16)
(115)
(131)
(35)
—
(35)
(523)
(306)
(829)
(6,569)
(2,808)
(3,761)
Fair value
asset
167
1,543
3,780
768
232
6,490
—
—
—
32
—
32
22
831
853
7,375
3,016
4,359
$ million
2016
Fair value
liability
(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)
Derivatives held for trading
The group maintains active trading positions in a variety of derivatives. The contracts may be entered into for risk management purposes, to
satisfy supply requirements or for entrepreneurial trading. Certain contracts are classified as held for trading, regardless of their original
business objective, and are recognized at fair value with changes in fair value recognized in the income statement. Trading activities are
undertaken by using a range of contract types in combination to create incremental gains by arbitraging prices between markets, locations and
time periods. The net of these exposures is monitored using market value-at-risk techniques as described in Note 27.
The following tables show further information on the fair value of derivatives and other financial instruments held for trading purposes.
Derivative assets held for trading have the following fair values and maturities.
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Other derivatives
Less than
1 year
186
1,280
1,122
420
—
3,008
Less than
1 year
102
1,178
1,238
305
132
2,955
1-2 years
2-3 years
3-4 years
4-5 years
31
177
609
188
—
1,005
8
99
428
81
—
616
5
66
328
60
—
459
3
14
288
38
—
343
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
$ million
2017
Total
237
1,637
3,580
885
115
6,454
$ million
2016
Total
167
1,543
3,780
768
232
6,490
Over
5 years
4
1
805
98
115
1,023
Over
5 years
2
2
891
74
100
1,069
At 31 December 2016 the group had a contingent consideration receivable in respect of the disposal of the Texas City refinery. The sale
agreement contained an embedded derivative and had been designated at fair value through profit or loss and shown within other derivatives
held for trading, within level 3 of the fair value hierarchy. The valuation was dependent on refinery throughput and future margins and final
payment was received in 2017.
174
BP Annual Report and Form 20-F 2017
28. Derivative financial instruments – continued
Derivative liabilities held for trading have the following fair values and maturities.
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Currency derivatives
Oil price derivatives
Natural gas price derivatives
Power price derivatives
Less than
1 year
(92)
(1,120)
(973)
(337)
(2,522)
Less than
1 year
(379)
(787)
(947)
(201)
(2,314)
1-2 years
2-3 years
3-4 years
4-5 years
(232)
(118)
(410)
(134)
(894)
(66)
(33)
(334)
(63)
(496)
(188)
(4)
(224)
(39)
(455)
(99)
(6)
(194)
(29)
(328)
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)
Over
5 years
(79)
—
(709)
(91)
(879)
Over
5 years
(744)
(6)
(765)
(82)
(1,597)
The following table shows the fair value of derivative assets and derivative liabilities held for trading, analysed by maturity period and by
methodology of fair value estimation. This information is presented on a gross basis, that is, before netting by counterparty.
Fair value of derivative assets
Level 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 2
Level 3
Less: netting by counterparty
Fair value of derivative liabilities
Level 2
Level 3
Less: netting by counterparty
Net fair value
Less than
1 year
3,663
386
4,049
(1,041)
3,008
(3,338)
(225)
(3,563)
1,041
(2,522)
486
Less than
1 year
3,962
448
4,410
(1,455)
2,955
(3,610)
(159)
(3,769)
1,455
(2,314)
641
1-2 years
2-3 years
3-4 years
4-5 years
1,003
258
1,261
(256)
1,005
(953)
(197)
(1,150)
256
(894)
111
438
231
669
(53)
616
(358)
(191)
(549)
53
(496)
120
244
226
470
(11)
459
(289)
(177)
(466)
11
(455)
4
140
211
351
(8)
343
(163)
(173)
(336)
8
(328)
15
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)
13
117
241
358
(9)
349
(401)
(177)
(578)
9
(569)
(220)
Over
5 years
135
899
1,034
(11)
1,023
(166)
(724)
(890)
11
(879)
144
Over
5 years
189
906
1,095
(26)
1,069
(872)
(751)
(1,623)
26
(1,597)
(528)
$ million
2017
Total
(756)
(1,281)
(2,844)
(693)
(5,574)
$ million
2016
Total
(2,000)
(952)
(2,845)
(560)
(6,357)
$ million
2017
Total
5,623
2,211
7,834
(1,380)
6,454
(5,267)
(1,687)
(6,954)
1,380
(5,574)
880
$ million
2016
Total
6,020
2,352
8,372
(1,882)
6,490
(6,611)
(1,628)
(8,239)
1,882
(6,357)
133
BP Annual Report and Form 20-F 2017
175
28. Derivative financial instruments – continued
Level 3 derivatives
The following table shows the changes during the year in the net fair value of derivatives held for trading purposes within level 3 of the fair
value hierarchy.
Fair value contracts at 1 January 2017
Gains (losses) recognized in the income statement
Settlements
Transfers out of level 3
Net fair value of contracts at 31 December 2017
Deferred day-one gains (losses)
Derivative asset (liability)
Fair value 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)
Oil
price
68
76
(68)
(9)
67
Oil
price
169
(37)
(63)
(1)
68
Natural gas
price
145
161
(35)
(206)
65
Natural gas
price
214
1
(51)
(19)
145
Power
price
(147)
61
(113)
(27)
(226)
Power
price
91
(82)
(145)
(11)
(147)
Other
231
15
(131)
—
115
Other
292
139
(200)
—
231
$ million
Total
297
313
(347)
(242)
21
503
524
$ million
Total
766
21
(459)
(31)
297
427
724
The amount recognized in the income statement for the year relating to level 3 held-for-trading derivatives still held at 31 December 2017 was a
$234-million gain (2016 $253-million loss related to derivatives still held at 31 December 2016).
Derivative gains and losses
The group enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchases contracts, relating
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. These gains and losses are included within sales and other operating revenues in the
income statement. Also included within this line item 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 $1,983 million (2016 $1,435 million net gain and 2015 $5,508 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 amounts for actual gains and losses relating to these derivative contracts and all related items therefore
differ significantly from the amounts disclosed above.
The group also enters into derivative contracts including futures, options, swaps and certain forward sales and forward purchase contracts
primarily relating to foreign currency risk management activities. Gains and losses on these contracts are included within production and
manufacturing expenses in the income statement. The change in the unrealized value of these contracts was a net gain of $1,420 million (2016
$154 million net loss and 2015 $833 million net loss), however the gains and losses in each year are largely offset by opposing net foreign
exchange differences on retranslation of the associated non-US dollar debt. The net amounts for actual gains and losses relating to these
derivative contracts and all related items therefore differ significantly from the amounts disclosed above.
Cash flow hedges
At 31 December 2017, the group held currency forwards used to hedge the foreign currency risk of highly probable forecast transactions. Note
27 outlines the group’s approach to foreign currency exchange risk management. For cash flow hedges the group only claims hedge
accounting for the spot value on the currency with any fair value attributable to forward points taken immediately to the income statement. The
amounts remaining in equity at 31 December 2017 in relation to these cash flow hedges consist of deferred losses of $21 million maturing in
2018, deferred gains of $8 million maturing in 2019 and deferred gains of $2 million maturing in 2020 and beyond.
Fair value hedges
At 31 December 2017, the group held interest rate and cross-currency interest rate swap contracts as fair value hedges of the interest rate risk
and foreign currency risk on fixed rate debt issued by the group. The gain on the hedging derivative instruments recognized in the income
statement in 2017 was $364 million (2016 $316-million loss and 2015 $788-million loss) offset by a loss on the fair value of the finance debt of
$394 million (2016 $270-million gain and 2015 $833-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 27 outlines the group’s approach to interest rate and foreign currency
exchange risk management.
176
BP Annual Report and Form 20-F 2017
29. Called-up share capital
The allotted, called up and fully paid share capital at 31 December was as follows:
Issued
8% cumulative first preference shares of £1 eacha
9% cumulative second preference shares of £1 eacha
Ordinary shares of 25 cents each
At 1 January
Issue of new shares for the scrip dividend programme
Issue of new shares – otherb
Repurchase of ordinary share capital
At 31 December
Shares
thousand
7,233
5,473
21,049,696
289,789
—
(51,292)
21,288,193
2017
$ million
12
9
21
5,263
72
—
(13)
5,322
5,343
Shares
thousand
7,233
5,473
20,108,771
548,005
392,920
—
21,049,696
2016
$ million
12
9
21
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
21
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 in consideration for a 10% interest in the Abu Dhabi onshore oil concession. See Note 30 for further information.
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes
for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands
vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the
preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid
up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous
six months over par value.
During 2017 the company repurchased 51 million ordinary shares for a total consideration of $343 million, including transaction costs of $2
million, as part of the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The
repurchased shares represented 0.2% of ordinary share capital.
Treasury sharesa
At 1 January
Purchases for settlement of employee share plans
Shares re-issued for employee share-based payment
plansb
At 31 December
Of which – shares held in treasury by BP
– shares held in ESOP trusts
– shares held by BP’s US share plan
administratorc
2017
Shares
thousand
1,614,657
4,423
Nominal value
$ million
403
1
Shares
thousand
1,756,327
9,631
2016
Nominal value
$ million
439
2
Shares
thousand
1,811,297
51,142
2015
Nominal value
$ million
453
13
(137,008)
(34)
(151,301)
(38)
(106,112)
1,482,072
1,472,343
9,705
24
370
368
2
—
1,614,657
1,576,411
21,432
403
394
5
1,756,327
1,727,763
18,453
16,814
4
10,111
(27)
439
432
4
3
a See Note 30 for definition of treasury shares.
b A minor amendment has been made to the number of shares re-issued for employee share-based payment plans in 2016.
c 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 7.5% (2016 8.6% and 2015 8.9%) of the called-up ordinary share capital of the company.
During 2017, the movement in shares held in treasury by BP represented less than 0.5% (2016 less than 0.8% and 2015 less than 0.2%) of the
ordinary share capital of the company.
BP Annual Report and Form 20-F 2017
177
30. Capital and reserves
At 1 January 2017
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
Repurchases of ordinary share capital
Share-based payments, net of taxb
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interestsc
At 31 December 2017
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 d
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 taxb
Share of equity-accounted entities’ changes in equity, net of tax
Transactions involving non-controlling interests
At 31 December 2015
Share
capital
Share
premium
account
Capital
redemption
reserve
Merger
reserve
5,284 12,219
—
—
1,413 27,206
—
—
Total
share capital
and capital
reserves
46,122
—
—
—
—
—
—
—
—
—
—
—
—
—
72
(13)
—
—
—
—
—
(72)
—
—
—
—
5,343 12,147
—
—
—
—
—
—
—
—
—
—
—
—
—
13
—
—
—
—
—
—
—
—
—
—
1,426 27,206
—
—
—
—
—
—
—
—
—
—
—
—
46,122
Share
capital
Share
premium
account
Capital
redemption
reserve
Merger
reserve
5,049 10,234
—
—
1,413 27,206
—
—
Total
share capital
and capital
reserves
43,902
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
137
98
—
—
—
—
(137)
2,122
—
—
5,284 12,219
—
—
—
—
—
—
—
—
—
—
—
—
1,413 27,206
—
—
—
—
—
—
—
—
2,220
—
—
46,122
Share
capital
Share
premium
account
Capital
redemption
reserve
Merger
reserve
5,023 10,260
—
—
1,413 27,206
—
—
Total
share capital
and capital
reserves
43,902
—
—
—
—
—
—
—
—
—
—
—
—
—
—
26
—
—
—
—
—
—
(26)
—
—
—
5,049 10,234
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,413 27,206
—
—
—
—
—
—
—
—
—
—
—
—
43,902
a Principally foreign exchange effects relating to the Russian rouble.
b Movements in treasury shares relate to employee share-based payment plans.
c Principally relates to the initial public offering of common units in BP Midstream Partners LP for which net proceeds of $811 million were received.
d 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.
178
BP Annual Report and Form 20-F 2017
30. Capital and reserves – continued
Cash flow
hedges
(1,156)
—
Total
fair value
reserves
(1,153)
—
Profit and
loss
account
75,638
3,389
BP
shareholders’
equity
95,286
3,389
Non-
controlling
interests
1,557
79
Treasury
shares
(18,443)
—
—
—
—
—
—
—
—
—
—
1,485
—
—
(16,958)
Treasury
shares
(19,964)
—
—
—
—
—
—
—
—
—
1,521
—
—
(18,443)
Treasury
shares
(20,719)
—
—
—
—
—
—
—
—
—
—
755
—
—
(19,964)
Foreign
currency
translation
reserve
(6,878)
—
1,722
—
—
—
—
—
1,722
—
—
—
—
—
(5,156)
Foreign
currency
translation
reserve
(7,267)
—
389
—
—
—
—
—
389
—
—
—
—
(6,878)
Foreign
currency
translation
reserve
(3,409)
—
(3,858)
—
—
—
—
—
—
(3,858)
—
—
—
—
(7,267)
Available-
for-sale
investments
3
—
—
14
—
—
—
—
14
—
—
—
—
—
17
—
—
396
—
—
—
396
—
—
—
—
—
(760)
—
14
396
—
—
—
410
—
—
—
—
—
(743)
Available-
for-sale
investments
Cash flow
hedges
Total
fair value
reserves
2
—
—
1
—
—
—
—
1
—
—
—
—
3
Available-
for-sale
investments
1
—
—
1
—
—
—
—
—
1
—
—
—
—
2
(825)
—
—
—
(331)
—
—
—
(331)
—
—
—
—
(1,156)
Cash flow
hedges
(898)
—
—
—
73
—
—
—
—
73
—
—
—
—
(825)
(823)
—
—
1
(331)
—
—
—
(330)
—
—
—
—
(1,153)
Total
fair value
reserves
(897)
—
—
1
73
—
—
—
—
74
—
—
—
—
(823)
$ million
Total equity
96,843
3,468
1,771
14
396
564
(72)
2,343
8,484
(6,294)
(343)
687
215
812
100,404
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
(3)
—
—
564
(72)
2,343
6,221
(6,153)
(343)
(798)
215
446
75,226
Profit and
loss
account
81,368
115
—
—
—
833
(96)
(1,757)
(905)
(4,611)
(750)
106
430
75,638
Profit and
loss
account
92,564
(6,482)
—
—
—
(814)
80
2,742
(1)
(4,475)
(6,659)
(99)
40
(3)
81,368
1,719
14
396
564
(72)
2,343
8,353
(6,153)
(343)
687
215
446
98,491
52
—
—
—
—
—
131
(141)
—
—
—
366
1,913
BP
shareholders’
equity
97,216
115
Non-
controlling
interests
1,171
57
389
1
(331)
833
(96)
(1,757)
(846)
(4,611)
2,991
106
430
95,286
(27)
—
—
—
—
—
30
(107)
—
—
463
1,557
BP
shareholders’
equity
111,441
(6,482)
Non-
controlling
interests
1,201
82
(3,858)
1
73
(814)
80
2,742
(1)
(8,259)
(6,659)
656
40
(3)
97,216
(41)
—
—
—
—
—
—
41
(91)
—
—
20
1,171
BP Annual Report and Form 20-F 2017
179
30. Capital and reserves – continued
Share capital
The balance on the share capital account represents the aggregate nominal value of all ordinary and preference shares in issue, including
treasury shares.
Share premium account
The balance on the share premium account represents the amounts received in excess of the nominal value of the ordinary and preference
shares.
Capital redemption reserve
The balance on the capital redemption reserve represents the aggregate nominal value of all the ordinary shares repurchased and cancelled.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares
issued in an acquisition made by the issue of shares.
Treasury shares
Treasury shares represent BP shares repurchased and available for specific and limited purposes. For accounting purposes shares held in
Employee Share Ownership Plans (ESOPs) 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.
180
BP Annual Report and Form 20-F 2017
30. Capital and reserves – continued
The pre-tax amounts of each component of other comprehensive income, and the related amounts of tax, are shown in the table below.
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Other comprehensive income
Items that may be reclassified subsequently to profit or loss
Currency translation differences (including recycling)
Available-for-sale investments (including recycling)
Cash flow hedges (including recycling)
Share of items relating to equity-accounted entities, net of tax
Other
Items that will not be reclassified to profit or loss
Remeasurements of the net pension and other post-retirement benefit liability or asset
Share of items relating to equity-accounted entities, net of tax
Other comprehensive income
31. Contingent liabilities
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.
Pre-tax
Tax
Net of tax
$ million
2017
1,866
14
425
564
—
3,646
6,515
(95)
—
(29)
—
(72)
(1,303)
(1,499)
1,771
14
396
564
(72)
2,343
5,016
$ 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)
Contingent liabilities not related to the Gulf of Mexico oil spill
There were contingent liabilities at 31 December 2017 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 27.
In the normal course of the group’s business, legal and regulatory 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 health, safety and 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.
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 including the tax
deductibility of certain intercompany charges. The resolution of tax positions through negotiations with relevant tax authorities, or through
litigation, can take several years to complete and the amounts could be significant and could be material to the group’s results of operations,
financial position or liquidity. 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 2017
181
31. Contingent liabilities – continued
The group is subject to numerous national and local health, safety and 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, commodities extraction sites, 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.
32. 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.
2017
2016
9
9
18
10
14
24
$ million
2015
10
14
24
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 2017, one executive director participated in a UK final salary pension plan in respect of service prior to 1 April 2011. During 2017, one
executive director participated in retirement savings plans established for US employees and in a US defined pension plan in respect of service
prior to 1 September 2016.
Further information
Full details of individual directors’ remuneration are given in the Directors’ remuneration report on page 90.
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
2017
2016
29
2
29
60
28
3
39
70
$ million
2015
33
4
36
73
Senior management comprises members of the executive team, see pages 66-67 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 $nil in 2017 (2016 $2.2 million and 2015 $nil).
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’.
182
BP Annual Report and Form 20-F 2017
33. Employee costs and numbers
Employee costs
Wages and salariesa
Social security costs
Share-based paymentsb
Pension and other post-retirement benefit costs
2017
7,572
711
624
1,296
10,203
2016
8,456
760
764
1,253
11,233
Average number of employeesc
US
Non-US
Upstream
Downstreamd e
Other businesses and corporatee f
6,200
6,100
1,900
14,200
12,200
35,900
12,400
60,500
2017
Total
18,400
42,000
14,300
74,700
US
Non-US
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
US
Non-US
7,900
7,800
1,700
17,400
15,100
38,200
11,900
65,200
$ million
2015
9,556
879
833
1,660
12,928
2015
Total
23,000
46,000
13,600
82,600
a Includes termination costs of $189 million (2016 $545 million and 2015 $857 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 16,500 (2016 15,800 and 2015 15,000) 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 from the global business
services organization were reallocated from Downstream to Other businesses and corporate during 2015.
f Includes 4,700 (2016 4,900 and 2015 5,300) agricultural, operational and seasonal workers in Brazil.
34. 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
Services relating to corporate finance transactions
Non-audit and other assurance services
Total non-audit or non-audit-related assurance services
Services relating to BP pension plansc
2017
2016
$ million
2015
26
11
37
7
44
—
—
3
3
—
47
25
12
37
7
44
1
—
1
2
1
47
27
13
40
7
47
1
1
1
3
1
51
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 audit of internal control over financial reporting and non-statutory audit services.
c The pension plan services include tax compliance service of $nil (2016 $nil and 2015 $0.4 million).
2017 includes $1.6 million of additional fees for 2016 and 2016 includes $1 million of additional fees for 2015. 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 other 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 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.
Under SEC regulations, the remuneration of the auditor of $47 million (2016 $47 million and 2015 $51 million) is required to be presented as
follows: audit $37 million (2016 $37 million and 2015 $40 million); other audit-related $7 million (2016 $7 million and 2015 $7 million); tax $nil
(2016 $1 million and 2015 $1 million); and all other fees $3 million (2016 $2 million and 2015 $3 million).
BP Annual Report and Form 20-F 2017
183
35. Subsidiaries, joint arrangements and associates
The more important subsidiaries and associates of the group at 31 December 2017 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
BP Exploration (Caspian Sea)
BP Exploration (Azerbaijan)
Canada
*BP Holdings Canada
Egypt
BP Exploration (Delta)
Germany
BP Europa SE
India
BP Exploration (Alpha)
Trinidad & Tobago
BP Trinidad and Tobago
UK
BP Capital Markets
US
*BP Holdings North America
Atlantic Richfield Company
BP America
BP America Production Company
BP Company North America
BP Corporation North America
BP Exploration (Alaska)
BP Products North America
Standard Oil Company
BP Capital Markets America
Associates
Russia
Rosneft
Country of
incorporation
%
Principal activities
100 England & Wales
100 England & Wales
100 England & Wales
100 England & Wales
100 England & Wales
100 Scotland
Investment holding
Exploration and production
Investment holding
Integrated oil operations
Integrated oil operations
Lubricants
100 England & Wales
Exploration and production
100 England & Wales
100 England & Wales
Exploration and production
Exploration and production
100 England & Wales
Investment holding
100 England & Wales
Exploration and production
100 Germany
Refining and marketing
100 England & Wales
Exploration and production
70 US
Exploration and production
100 England & Wales
Finance
100 England & Wales
100 US
100 US
100 US
100 US
100 US
100 US
100 US
100 US
100 US
Investment holding
Exploration and production, refining and
marketing
Finance
Country of
incorporation
%
Principal activities
20 Russia
Integrated oil operations
184
BP Annual Report and Form 20-F 2017
36. Condensed consolidating information on certain US subsidiaries
BP p.l.c. fully and unconditionally guarantees the payment obligations of its 100%-owned subsidiary BP Exploration (Alaska) Inc. under the BP
Prudhoe Bay Royalty Trust. The following financial information for BP p.l.c., BP Exploration (Alaska) Inc. and all other subsidiaries on a
condensed consolidating basis is intended to provide investors with meaningful and comparable financial information about BP p.l.c. and its
subsidiary issuers of registered securities and is provided pursuant to Rule 3-10 of Regulation S-X in lieu of the separate financial statements of
each subsidiary issuer of public debt securities. 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 taxesa
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
BP p.l.c.
Other
subsidiaries
Eliminations
and
reclassifications
3,264
—
—
—
11
71
3,346
1,010
1,156
(18)
735
—
—
19
444
6
—
438
(392)
830
830
—
830
—
—
—
4,436
369
9
4,814
—
—
—
—
—
—
616
4,198
826
(15)
3,387
(11)
3,398
3,398
—
3,398
240,177
1,177
1,330
—
1,470
1,139
245,293
181,939
23,073
1,793
14,849
1,216
2,080
10,022
10,321
2,286
235
7,800
4,115
3,685
3,606
79
3,685
(3,233)
—
—
(4,436)
(1,193)
(9)
(8,871)
(3,233)
—
—
—
—
—
(149)
(5,489)
(1,044)
—
(4,445)
—
(4,445)
(4,445)
—
(4,445)
a Includes revised non-cash provision adjustments; actual cash payments for Production and similar taxes remain in line with prior year.
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.
830
—
—
830
830
—
830
Other
subsidiaries
Eliminations
and
reclassifications
3,685
3,035
—
6,720
6,589
131
6,720
(4,445)
—
(2,983)
(7,428)
(7,428)
—
(7,428)
BP p.l.c.
3,398
1,981
2,983
8,362
8,362
—
8,362
$ million
2017
BP group
240,208
1,177
1,330
—
657
1,210
244,582
179,716
24,229
1,775
15,584
1,216
2,080
10,508
9,474
2,074
220
7,180
3,712
3,468
3,389
79
3,468
$ million
2017
BP group
3,468
5,016
—
8,484
8,353
131
8,484
BP Annual Report and Form 20-F 2017
185
36. Condensed consolidating information on certain US subsidiaries – continued
Income statement continued
For the year ended 31 December
Sales and other operating revenues
Earnings from joint ventures - after interest and tax
Earnings from associates - after interest and tax
Equity-accounted income of subsidiaries - after interest and tax
Interest and other income
Gains on sale of businesses and fixed assets
Total revenues and other income
Purchases
Production and manufacturing expenses
Production and similar taxes
Depreciation, depletion and amortization
Impairment and losses on sale of businesses and fixed assets
Exploration expense
Distribution and administration expenses
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
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
85
—
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
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.
85
—
—
85
85
—
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)
186
BP Annual Report and Form 20-F 2017
36. Condensed consolidating information on certain US subsidiaries – continued
Income statement continued
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 continued
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.
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
20
(6,369)
82
(6,451)
(6,451)
—
(6,451)
Other
subsidiaries
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
Eliminations and
reclassifications
(3,425)
—
—
5,404
(274)
(31)
1,674
(3,425)
—
—
—
—
—
(77)
5,176
(197)
286
(8,274)
(3,124)
(5,150)
(5,232)
82
(5,150)
—
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)
BP Annual Report and Form 20-F 2017
187
36. Condensed consolidating information on certain US subsidiaries – continued
Balance sheet
Issuer
Guarantor
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
BP Exploration
(Alaska) Inc.
6,973
—
585
—
—
—
—
7,558
1
—
—
—
—
—
7,559
—
274
2,206
—
2
—
—
—
2,482
10,041
673
—
115
—
—
1
789
—
—
—
—
838
1,222
—
2,060
2,849
7,192
7,192
—
7,192
BP p.l.c.
—
—
—
—
2
—
161,840
161,842
—
2,623
—
—
—
3,838
168,303
—
—
293
—
—
—
—
10
303
168,606
7,843
—
60
—
—
—
7,903
34,104
—
—
—
1,337
—
221
35,662
43,565
125,041
125,041
—
125,041
Other
subsidiaries
Eliminations
and
reclassifications
122,498
11,551
17,770
7,994
16,989
1,245
—
178,047
34,701
1,434
4,110
1,112
4,469
331
224,204
190
18,737
32,691
3,032
1,412
761
125
25,576
82,524
306,728
46,034
2,808
4,785
7,739
1,686
3,323
66,375
16,464
3,761
505
55,491
5,807
19,398
8,916
110,342
176,717
130,011
128,098
1,913
130,011
—
—
—
—
—
—
(161,840)
(161,840)
(34,056)
(2,623)
—
—
—
—
(198,519)
—
—
(10,341)
—
—
—
—
—
(10,341)
(208,860)
(10,341)
—
—
—
—
—
(10,341)
(36,679)
—
—
—
—
—
—
(36,679)
(47,020)
(161,840)
(161,840)
—
(161,840)
$ million
2017
BP group
129,471
11,551
18,355
7,994
16,991
1,245
—
185,607
646
1,434
4,110
1,112
4,469
4,169
201,547
190
19,011
24,849
3,032
1,414
761
125
25,586
74,968
276,515
44,209
2,808
4,960
7,739
1,686
3,324
64,726
13,889
3,761
505
55,491
7,982
20,620
9,137
111,385
176,111
100,404
98,491
1,913
100,404
188
BP Annual Report and Form 20-F 2017
36. Condensed consolidating information on certain US subsidiaries – continued
Balance sheet continued
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 receivablesa
Derivative financial instruments
Prepayments
Current tax receivable
Other investments
Cash and cash equivalents
Total assets
Current liabilities
Trade and other payablesa
Derivative financial instruments
Accruals
Finance debt
Current tax payablea
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’ equitya
Non-controlling interests
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
1,593
—
7
—
—
—
1,849
9,841
672
—
116
—
—
2
790
20
—
—
—
1,279
1,390
—
2,689
3,479
6,362
6,362
—
6,362
—
—
—
—
2
—
156,864
156,866
—
2,951
—
—
—
528
160,345
—
—
487
—
—
—
—
50
537
160,882
4,096
—
129
—
—
—
4,225
34,389
—
43
—
179
—
219
34,830
39,055
121,827
121,827
—
121,827
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
24,610
3,016
1,479
1,194
44
23,434
71,442
292,841
39,162
2,991
4,891
6,634
1,666
4,010
59,354
16,906
5,513
426
51,666
5,780
19,022
8,656
107,969
167,323
125,518
123,961
1,557
125,518
—
—
—
—
—
—
(156,864)
(156,864)
(34,418)
(2,951)
—
—
—
—
(194,233)
—
—
(6,015)
—
—
—
—
—
(6,015)
(200,248)
(6,015)
—
—
—
—
—
(6,015)
(37,369)
—
—
—
—
—
—
(37,369)
(43,384)
(156,864)
(156,864)
—
(156,864)
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
259
17,655
20,675
3,016
1,486
1,194
44
23,484
67,813
263,316
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
108,119
166,473
96,843
95,286
1,557
96,843
a Amendments have been made to previously reported amounts for BP Exploration (Alaska) Inc., reducing current trade and other receivables by $990 million, current trade and other payables
by $50 million and current tax payable by $11 million, with offsetting amendments to BP shareholders' equity. This relates to intra-BP group balances and, as such, amendments have also
been made to the same line items presented for Other subsidiaries as well as eliminations amounts. The amendments represent the adjustment of amounts recorded in earlier periods by
BP Exploration (Alaska) Inc. as intra-BP group balances relating to group re-organizations and the tax consequences thereon which are now considered to be more appropriately treated as
shown by the amended amounts above.
BP Annual Report and Form 20-F 2017
189
36. Condensed consolidating information on certain US subsidiaries – continued
Cash flow statement
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
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
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
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
227
(227)
—
—
—
—
—
BP p.l.c.
6,456
—
(6,496)
—
(40)
50
10
Other
subsidiaries
12,248
(13,850)
3,200
544
2,142
23,434
25,576
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
699
(699)
—
—
—
—
—
BP p.l.c.
4,661
—
(4,611)
—
50
—
50
Issuer
Guarantor
BP Exploration
(Alaska) Inc.
925
(925)
—
—
—
—
—
BP p.l.c.
6,628
—
(6,659)
—
(31)
31
—
Other
subsidiaries
5,331
(14,054)
6,588
(820)
(2,955)
26,389
23,434
Other
subsidiaries
11,580
(16,375)
2,124
(672)
(3,343)
29,732
26,389
$ million
2017
BP group
18,931
(14,077)
(3,296)
544
2,102
23,484
25,586
$ 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
190
BP Annual Report and Form 20-F 2017
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)
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.
(ii)
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)
(ii)
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
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 259-264.
BP Annual Report and Form 20-F 2017
191
Oil and natural gas exploration and production activities
Europe
Rest of
Europe
UK
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
$ million
2017
34,208
481
34,689
21,793
12,896
— 83,449
— 3,957
— 87,406
— 48,462
— 38,944
3,518
2,561
6,079
367
5,712
13,581
2,905
16,486
7,495
8,991
49,795
4,013
53,808
34,870
18,938
— 35,519
— 3,407
— 38,926
— 18,007
— 20,919
562
5,984 226,054
17,886
6,546 243,940
3,192 134,186
3,354 109,754
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
Costs incurred for the year ended 31 Decembera b
Acquisition of properties
Proved
Unproved
Exploration and appraisal costsc
Development
Total costs
—
13
13
336
995
1,344
Results of operations for the year ended 31 Decembera
Sales and other operating revenuesd
204
1,745
1,949
331
629
(37)
(272)
1,190
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
22
—
13
—
35
—
—
102
— 2,776
— 2,913
724
—
— 9,117
— 9,841
—
282
— 2,256
52
—
2
1,655
— 4,258
—
—
—
52
58
110
171
2
173
39
116
—
34
96
133
(12)
87
1,974
(25)
(104)
79
8,590
(10)
10
1,251
— (1,811)
3,062
10
(1)
284
(111)
(28)
(83)
—
330
330
264
911
1,505
564
374
938
682
2,972
4,592
— 1,187
—
228
— 1,415
11
190
— 2,760
4,365
11
—
—
—
18
223
241
1,773
958
2,731
1,655
10,695
15,081
1,134
327
1,461
83
573
86
71
742
(31)
1,524
(63)
155
(218)
2,211
4,022
6,233
1,346
979
—
280
3,586
—
6,191
42
788
(746)
— 1,276
— 6,394
— 7,670
(29)
11
904
—
— 1,618
39
311
— 2,147
—
50
(50)
(19)
(31)
(10)
4,941
2,729
1,505
1,224
967
487
1,454
17
157
56
349
366
13
958
496
146
350
6,687
22,094
28,781
2,080
5,614
1,775
2,469
12,385
179
24,502
4,279
632
3,647
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 j
Total replacement cost profit (loss)
before interest and tax
(25)
10
1,251
(111)
(63)
42
(50)
2,729
496
4,279
(185)
—
97
71
(176)
(111)
25
—
(210)
178
1,100
(222)
140
381
458
(80)
205
3
837
315
245
11
—
14
1,764
167
790
3,289
507
6,057
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, Asia and
Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the South Caucasus Pipeline, the Forties Pipeline System and the Baku-
Tbilisi-Ceyhan pipeline. The Forties Pipeline System was divested on 31 October 2017. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as
incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes, other government take and the fair value gain on embedded derivatives of $32 million. The UK region includes a $343-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 $120 million which is included in finance costs in the group income statement.
g US region includes the deferred tax impact of the reduction in the US Federal corporate income tax rate from 35% to 21% enacted in December 2017.
h Midstream and other activities excludes inventory holding gains and losses.
i The profits of equity-accounted entities are included after interest and tax.
j From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas
Corporation. Of BP's initial 60% interest in PAE, 10% was classified as held for sale on 9 September 2017. For September, only 9 days of income was reported for the full 60%. After this
equity accounting continued for the 50% not classified as held for sale. BP accounted for 50% of the enlarged entity from 16 December 2017.
192
BP Annual Report and Form 20-F 2017
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russiaa
Rest of
Asia
$ million
2017
Equity-accounted entities (BP share)
Capitalized costs at 31 Decemberb c
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
— 3,187
—
481
— 3,668
400
—
— 3,268
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 operationsg
—
—
—
—
—
—
—
—
—
—
—
—
—
323
152
475
49
199
723
773
—
773
68
157
—
67
328
6
626
147
54
93
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 9,096
—
68
— 9,164
— 4,249
— 4,915
— 24,686
—
907
— 25,593
— 6,207
— 19,386
3,434
26
3,460
3,460
—
—
—
—
—
—
—
—
20
20
43
576
639
— 1,750
—
—
— 1,750
—
—
592
—
336
—
11
—
458
—
653
—
—
416
— 1,069
—
194
— 3,361
— 4,624
—
—
— 11,537
— 11,537
—
59
— 1,424
— 5,712
—
409
— 1,539
—
27
—
54
— 1,424
326
—
(18)
—
344
—
— 9,197
— 2,340
—
457
— 1,883
—
—
—
—
446
446
988
—
988
—
117
426
(5)
446
—
984
4
—
4
— 40,403
— 1,482
— 41,885
— 14,316
— 27,569
976
—
—
588
— 1,564
—
286
— 4,582
— 6,432
— 3,511
— 11,537
— 15,048
—
127
— 2,290
— 6,474
—
482
— 2,771
—
87
— 12,231
— 2,817
—
493
— 2,324
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
—
—
—
93
(22)
71
—
25
25
—
—
—
344
37
381
— 1,883
205
(1,046)
205
837
4
241
245
— 2,324
—
(560)
— 1,764
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 and Pan American Energy Group 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 From 16 December 2017, BP entered into a new 50:50 joint venture Pan American Energy Group (PAEG). Prior to this, Pan American Energy (PAE) was owned 60% by BP and 40% by Bridas
Corporation. Of BP's initial 60% interest in PAE, 10% was classified as held for sale on 9 September 2017. For September, only 9 days of income was reported for the full 60%. After this
equity accounting continued for the 50% not classified as held for sale. BP accounted for 50% of the enlarged entity from 16 December 2017.
h Includes interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
BP Annual Report and Form 20-F 2017
193
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
$ million
2016
34,171
483
34,654
21,745
12,909
— 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
562
5,752 215,564
18,524
6,314 234,088
2,826 123,993
3,488 110,095
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
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
314
38
352
391
2,372
3,115
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
244
1,387
1,631
133
619
(351)
(215)
1,002
(809)
379
1,252
(286)
1,538
26
421
447
3
208
—
37
209
(345)
112
335
(287)
622
640
6,204
6,844
693
2,524
155
1,687
3,940
(627)
8,372
(1,528)
(402)
(1,126)
—
10
10
70
28
108
74
2
76
61
114
—
25
66
—
10
10
123
1,519
1,652
747
103
850
672
476
38
115
591
—
181
181
297
2,957
3,435
1,215
3,391
4,606
87
1,220
—
597
2,937
(5)
261
(185)
(40)
(145)
(77)
(765)
1,815
(965)
(194)
(771)
4,076
530
670
(140)
—
703
— 1,728
— 2,431
10
252
— 2,788
5,471
10
207
—
207
89
194
490
1,439
1,967
3,406
1,402
11,145
15,953
97
—
— 3,908
— 4,005
(27)
10
691
—
800
—
34
115
— 2,179
—
44
(44)
(10)
(34)
(182)
3,576
429
(74)
503
1,042
309
1,351
89
154
41
153
289
63
789
562
288
274
4,085
15,725
19,810
1,721
6,006
683
2,548
11,213
(2,747)
19,424
386
(335)
721
Upstream and Rosneft segments replacement cost profit (loss) before interest and tax
Exploration and production activities –
1,252
335
(1,528)
(185)
(965)
530
(44)
429
562
386
subsidiaries (as above)
Midstream and other activities –
subsidiariesi
Equity-accounted entitiesj k
Total replacement cost profit (loss)
before interest and tax
(417)
—
54
(1)
(14)
20
(137)
—
187
447
(142)
(2)
(12)
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, Asia 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.
194
BP Annual Report and Form 20-F 2017
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russiaa
Rest of
Asia
$ million
2016
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
—
—
—
—
—
—
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
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
18
54
72
162
—
162
13
36
—
(13)
48
—
84
78
75
3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 10,211
—
6
— 10,217
— 4,615
— 5,602
— 19,558
—
383
— 19,941
— 4,401
— 15,540
3,009
26
3,035
3,035
—
—
—
—
—
—
—
—
—
—
7
559
566
— 1,576
—
69
— 1,645
—
118
— 2,070
— 3,833
— 1,865
—
—
— 1,865
—
—
559
—
335
—
(429)
—
499
—
—
—
— 8,088
— 8,088
—
50
— 1,085
— 3,393
—
345
— 1,082
—
164
—
59
— 1,128
737
—
319
—
418
—
— 6,014
— 2,074
—
435
— 1,639
—
—
—
1
371
372
876
16
892
—
145
352
3
386
—
886
6
3
3
— 35,480
—
711
— 36,191
— 12,099
— 24,092
— 1,576
—
69
— 1,645
—
144
— 3,054
— 4,843
— 2,903
— 8,104
— 11,007
—
63
— 1,825
— 4,080
—
(94)
— 2,015
—
223
— 8,112
— 2,895
—
832
— 2,063
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
—
—
—
3
(4)
(1)
—
20
20
—
—
—
418
29
447
— 1,639
(12)
(1,042)
(12)
597
3
263
266
— 2,063
—
(746)
— 1,317
a Amounts reported for Russia in this table include BP’s share of Rosneft’s worldwide activities, including insignificant amounts outside Russia. Amounts also include certain adjustments,
mainly related to purchase price allocations for 2016 acquisitions.
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 2017
195
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
$ million
2015
33,214
437
33,651
21,447
12,204
10,568
168
10,736
7,172
3,564
80,716
5,602
86,318
43,290
43,028
3,559
2,377
5,936
191
5,745
11,051
2,964
14,015
6,251
7,764
42,807
4,635
47,442
29,406
18,036
— 28,474
— 2,740
— 31,214
— 15,967
— 15,247
933
5,177 215,566
19,856
6,110 235,422
2,677 126,401
3,433 109,021
Subsidiaries
Capitalized costs at 31 Decembera b
Gross capitalized costs
Proved properties
Unproved properties
Accumulated depreciation
Net capitalized costs
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
Results of operations for the year ended 31 Decembera
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
496
1,149
1,645
115
879
(273)
(795)
949
(390)
485
1,160
(930)
2,090
—
—
—
11
73
84
209
718
927
8
313
—
92
544
131
56
187
651
3,662
4,500
651
7,427
8,078
960
2,777
215
2,460
3,671
—
—
—
75
324
399
14
2
16
108
77
—
48
13
—
(118)
(118)
114
1,299
1,295
1,594
33
1,627
51
703
214
140
673
259
8
267
533
2,749
3,549
1,829
4,005
5,834
1,001
1,521
—
358
3,412
17
974
(47)
159
(206)
340
10,423
(2,345)
(857)
(1,488)
—
246
(230)
(5)
(225)
101
846
1,882
(255)
(28)
(227)
7,138
(1,304)
694
(1,998)
—
—
—
—
—
—
5
102
— 3,439
3,541
5
—
—
—
125
128
253
407
(54)
353
1,794
13,458
15,605
800
—
— 4,028
— 4,828
5
53
— 1,083
834
—
27
76
— 2,420
—
32
(32)
(5)
(27)
105
4,571
257
(66)
323
1,450
340
1,790
52
166
46
215
322
140
941
849
472
377
7,043
17,702
24,745
2,353
7,519
1,036
2,621
12,004
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)
before interest and tax
1,160
(47)
(2,345)
(230)
(255)
(1,304)
(32)
257
849
(1,947)
401
—
110
(7)
43
19
10
—
211
370
(39)
(16)
(552) 1,326
1,561
56
(2,283)
(220)
326
(1,895) 1,278
67
363
687
14
—
801
1,519
863
373
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, Asia and
Europe are excluded. The most significant midstream pipeline interests include the Trans-Alaska Pipeline System, the Forties Pipeline System, the Central Area Transmission System pipeline,
the South Caucasus Pipeline and the Baku-Tbilisi-Ceyhan pipeline. Major LNG activities are located in Trinidad, Indonesia, Australia and Angola.
b Decommissioning assets are included in capitalized costs at 31 December but are excluded from costs incurred for the year.
c Includes exploration and appraisal drilling expenditures, which are capitalized within intangible assets, and geological and geophysical exploration costs, which are charged to income as
incurred.
d Presented net of transportation costs, purchases and sales taxes.
e Includes property taxes, other government take and the fair value gain on embedded derivatives of $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.
196
BP Annual Report and Form 20-F 2017
Oil and natural gas exploration and production activities – continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
Russiaa
Rest of
Asia
$ million
2015
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
— 12,728
—
437
— 13,165
— 2,788
— 10,377
3,486
26
3,512
3,458
54
—
—
—
—
—
—
—
8
— 1,128
— 1,136
16
—
26
—
42
—
—
123
— 1,702
— 1,867
—
—
—
1
443
444
— 2,060
—
—
— 2,060
3
—
647
—
425
—
(381)
—
465
—
—
— 8,592
— 8,592
—
52
— 1,083
— 3,911
284
—
992
—
— 1,022
19
1,041
—
168
388
—
484
—
80
—
—
35
— 1,239
821
—
504
—
317
—
— 6,322
— 2,270
—
449
— 1,821
1,075
(34)
1
(35)
— 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
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)
(7)
—
19
19
—
—
—
317
53
— 1,821
(552)
(495)
(35)
398
— 2,103
—
(584)
370
(552)
1,326
363
— 1,519
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 interest and adjustment for non-controlling interests. Excludes inventory holding gains and losses.
BP Annual Report and Form 20-F 2017
197
Movements in estimated net proved reserves
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
USc
Crude oila b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decemberg
Developed
Undeveloped
Africa
Asia
Australasia
Total
million barrels
2017
Russia
Rest of
Asia
— 1,107
—
245
— 1,352
—
—
—
—
—
—
—
407
—
—
42
(119)
—
330
— 1,040
642
—
— 1,682
317
42
358
35
2
1
—
(88)
—
(50)
281
28
309
3,162
1
— 2,134
5,296
1
—
—
—
—
—
—
—
102
—
37
264
(325)
—
78
1
3,124
— 2,251
5,374
1
43
1
44
(1)
—
—
—
(36)
—
(37)
6
—
6
318
42
360
282
28
310
3,162
2,134
5,296
3,124
2,251
5,374
1,150
246
1,395
1,047
642
1,688
32
14
46
2
—
—
—
(6)
—
(4)
31
11
42
2,487
1,291
3,778
673
14
5
53
(384)
(9)
351
2,592
1,537
4,129
— 3,573
— 2,529
— 6,101
—
—
—
—
—
—
—
104
16
71
288
(401)
(103)
(25)
— 3,473
— 2,603
— 6,076
32
14
46
31
11
42
6,060
3,819
9,879
6,064
4,140
10,205
9
11
20
1
—
—
—
(5)
—
(4)
10
6
16
321
325
646
1
4
—
22
(28)
(98)
(98)
285
263
548
330
336
666
295
269
564
155
274
429
15
—
3
—
(29)
(9)
(20)
245
164
409
—
—
—
—
—
—
—
—
—
—
—
—
—
155
274
429
826
—
—
497
— 1,322
42
209
251
—
—
—
—
—
—
—
208
12
1
12
(131)
—
101
5
—
—
—
(7)
—
(2)
—
932
492
—
— 1,423
54
195
248
45
69
114
2
11
34
1
(11)
(5)
31
56
89
145
45
69
114
—
—
—
—
—
—
—
—
—
—
—
—
—
826
497
1,322
932
492
1,423
—
—
—
—
—
—
—
—
—
—
—
—
—
42
209
251
54
195
249
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
245
164
409
56
89
145
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 Includes 5 million barrels of crude oil in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
e Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
f Includes 337 million barrels of crude oil in respect of the 6.31% non-controlling interest in Rosneft, including 32 mmbbl held through BP’s equity-accounted interest in Taas-Yuryakh
Neftegazodobycha.
g Total proved crude oil reserves held as part of our equity interest in Rosneft is 5,402 million barrels, comprising less than 1 million barrels in Vietnam and Canada, 59 million barrels in
Venezuela and 5,342 million barrels in Russia.
198
BP Annual Report and Form 20-F 2017
Movements in estimated net proved reserves - continued
Europe
North
America
South
America
Africa
Asia
Australasia
Total
million barrels
2017
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
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
UK
13
3
16
2
—
—
—
(3)
(1)
(2)
11
3
14
—
—
—
—
—
—
—
—
—
—
—
—
—
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
13
3
16
At 31 December
Developed
Undeveloped
11
3
14
—
—
—
—
—
—
—
—
—
—
—
—
—
3
2
5
—
1
2
—
(1)
—
3
4
4
8
3
2
5
4
4
8
226
73
299
(44)
15
—
1
(24)
—
(52)
177
69
246
—
—
—
—
—
—
—
—
—
—
—
—
—
226
73
299
177
69
246
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5
28
33
—
—
—
—
(3)
—
(3)
2
28
30
—
—
—
—
—
—
—
—
—
—
—
—
—
5
28
33
2
28
30
13
1
14
11
—
—
—
(4)
—
7
21
—
21
11
—
11
1
—
—
—
(1)
—
(1)
10
—
10
24
1
25
31
—
31
—
—
—
—
—
—
—
—
—
—
—
—
—
50
15
65
68
—
—
—
(2)
—
66
82
49
131
50
15
65
82
49
131
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9
2
11
(4)
—
—
—
(1)
—
(5)
5
1
6
—
—
—
—
—
—
—
—
—
—
—
—
—
9
2
11
5
1
6
266
107
373
(36)
15
—
1
(35)
(1)
(55)
216
102
318
65
17
81
69
1
2
—
(4)
—
68
97
53
149
331
123
454
313
154
467
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 2 thousand barrels per day for equity-accounted entities.
d Includes 9 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 131 million barrels, comprising less than 1 million barrels in Venezuela, Vietnam and Canada, and 131 million barrels
in Russia.
BP Annual Report and Form 20-F 2017
199
Movements in estimated net proved reserves - continued
Europe
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
USc
Total liquidsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productiond
Sales of reserves-in-place
At 31 Decembere
Developed
Undeveloped
Equity-accounted entities (BP share)f
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Production
Sales of reserves-in-place
At 31 Decembergh
Developed
Undeveloped
million barrels
2017
Africa
Asia
Australasia
Total
Russia
Rest of
Asia
— 1,107
—
245
— 1,352
—
—
—
—
—
—
—
407
—
—
42
(119)
—
330
— 1,040
642
—
— 1,682
330
43
372
45
2
1
—
(92)
—
(43)
301
28
329
3,213
12
— 2,148
5,361
12
1
—
—
—
(2)
—
(1)
170
—
37
264
(327)
—
144
11
3,206
— 2,300
5,505
12
43
1
44
(1)
—
—
—
(36)
—
(37)
6
—
6
342
43
385
313
28
341
3,213
2,148
5,361
3,206
2,300
5,505
1,150
246
1,395
1,047
642
1,688
42
16
57
(2)
—
—
—
(7)
—
(9)
36
12
48
2,753
1,398
4,151
637
29
5
54
(419)
(10)
296
2,808
1,639
4,447
— 3,637
— 2,545
— 6,183
—
—
—
—
—
—
—
174
17
72
288
(405)
(104)
43
— 3,569
— 2,656
— 6,225
42
16
57
36
12
48
6,390
3,943
10,333
6,377
4,295
10,672
14
39
53
1
—
—
—
(8)
—
(7)
12
34
46
321
325
646
1
4
—
22
(28)
(98)
(98)
285
263
548
335
364
699
297
297
594
168
277
445
17
—
3
—
(32)
(10)
(22)
256
167
424
—
—
—
—
—
—
—
—
—
—
—
—
—
168
277
445
— 1,051
—
569
— 1,621
42
209
251
—
—
—
—
—
—
—
164
27
1
12
(155)
—
49
5
—
—
—
(7)
—
(2)
— 1,108
561
—
— 1,669
54
195
248
48
71
119
2
13
36
1
(12)
(6)
34
60
93
153
48
71
119
—
—
—
—
—
—
—
—
—
—
—
—
—
1,051
569
1,621
1,108
561
1,669
—
—
—
—
—
—
—
—
—
—
—
—
—
42
209
251
54
195
249
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
256
167
424
60
93
153
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 Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 2 thousand barrels per day for equity-accounted entities.
e Also includes 14 million barrels in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
f Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
g Includes 338 million barrels in respect of the non-controlling interest in Rosneft, including 32 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh Neftegazodobycha.
h Total proved liquid reserves held as part of our equity interest in Rosneft is 5,533 million barrels, comprising less than 1 million barrels in Canada, 59 million barrels in Venezuela, less than
1 million barrels in Vietnam and 5,473 million barrels in Russia.
200
BP Annual Report and Form 20-F 2017
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
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Total
billion cubic feet
2017
Russia
Rest of
Asia
499
350
848
50
—
25
—
(77)
(4)
(5)
523
320
843
—
—
—
—
—
—
—
—
—
—
—
—
—
— 5,447
— 2,567
— 8,014
(38)
—
— 1,002
—
—
—
10
(664)
—
—
—
309
—
— 5,238
— 3,086
— 8,323
89
21
110
19
37
39
1
(19)
(6)
70
112
69
180
—
—
—
—
—
—
—
—
—
—
—
—
—
— 1,784
— 4,970
— 6,755
767
2,191
2,958
— 1,890
— 3,769
— 5,659
3,012
1,643
4,654
13,398
15,490
28,888
3
—
—
—
(3)
—
—
(677)
—
—
829
(714)
—
(562)
(450)
1
527
14
(380)
—
(288)
258
—
6
—
—
—
— 1,229
(152)
—
—
—
— 1,342
(129)
(983)
— 1,009
—
552
— 2,082
(2,281)
(4)
376
(291)
—
(420)
(1)
2,862
— 3,330
6,193
(1)
1,159
1,510
2,670
— 2,755
— 4,245
— 7,000
2,730
1,505
4,235
15,266
13,997
29,263
— 1,546
534
—
2,080
1
—
—
—
—
—
—
—
47
55
—
67
(178)
(347)
(356)
412
5,544
— 6,304
11,847
412
5
—
237
—
(32)
—
210
1,556
—
10
324
(488)
—
1,403
— 1,274
—
450
— 1,724
476
146
622
6,077
7,173
13,250
26
4
30
(2)
—
—
—
(8)
—
(10)
17
3
20
— 7,617
— 6,863
— 14,480
— 1,625
92
—
286
—
392
—
(726)
—
(353)
—
— 1,316
— 7,955
— 7,841
— 15,796
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
499
350
848
89
21
110
At 31 December
Developed
Undeveloped
523
320
843
112
69
180
5,447
2,567
8,014
5,238
3,086
8,323
— 3,330
— 5,505
— 8,835
— 4,136
— 3,781
— 7,917
1,179
2,191
3,370
1,635
1,656
3,291
5,544
6,304
11,847
6,077
7,173
13,250
1,916
3,772
5,688
2,771
4,249
7,020
3,012
1,643
4,654
2,730
1,505
4,235
21,015
22,353
43,368
23,221
21,838
45,060
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 180 billion cubic feet of natural gas consumed in operations, 131 billion cubic feet in subsidiaries, 49 billion cubic feet in equity-accounted entities.
d Includes 1,860 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 306 billion cubic feet of natural gas in respect of the 2.30% non-controlling interest in Rosneft including 12 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 13,522 billion cubic feet, comprising 0 billion cubic feet in Canada, 28 billion cubic feet in Venezuela, 19 billion cubic
feet in Vietnam, 237 billion cubic feet in Egypt and 13,237 billion cubic feet in Russia.
BP Annual Report and Form 20-F 2017
201
Movements in estimated net proved reserves – continued
Total hydrocarbonsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione f
Sales of reserves-in-place
At 31 Decemberg
Developed
Undeveloped
Equity-accounted entities (BP share)h
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
Productione
Sales of reserves-in-place
At 31 Decemberi j
Developed
Undeveloped
Europe
North
America
South
America
UK
Rest of
Europe
USd
Rest of
North
America
million barrels of oil equivalentc
2017
Africa
Asia
Australasia
Total
254
338
592
25
—
8
—
(45)
(11)
(23)
347
222
569
—
—
—
—
—
—
—
—
—
—
—
—
—
254
338
592
— 1,990
— 1,012
— 3,002
42
209
251
321
896
1,217
—
—
—
—
—
—
—
157
200
1
14
(270)
—
102
5
—
—
—
(8)
—
(2)
(116)
—
—
143
(131)
—
(104)
— 2,011
— 1,093
— 3,104
54
195
248
505
608
1,114
462
420
882
(32)
2
92
3
(157)
—
(93)
501
288
790
Russia
Rest of
Asia
— 1,433
—
895
— 2,327
—
—
—
—
—
—
—
451
1
—
254
(145)
—
562
— 1,515
— 1,374
— 2,889
63
75
138
5
19
42
1
(15)
(7)
46
80
105
184
63
75
138
—
—
—
—
—
—
—
—
—
—
—
—
—
1,990
1,012
3,002
2,011
1,093
3,104
588
—
—
417
— 1,005
4,168
83
— 3,235
7,404
83
—
—
—
—
—
—
—
—
—
—
42
209
251
54
195
249
9
14
—
34
(58)
(158)
(159)
505
341
846
909
1,313
2,222
1,010
949
1,959
2
—
41
—
(7)
—
35
93
25
119
545
420
966
595
314
908
439
—
38
320
(411)
—
386
4,254
3,536
7,790
4,168
3,235
7,404
4,254
3,536
7,790
47
1
49
(1)
—
—
—
(38)
—
(39)
9
1
10
1,480
896
2,376
1,524
1,374
2,899
561
299
860
(24)
—
—
—
(57)
—
(81)
507
272
779
5,063
4,068
9,131
467
203
100
413
(812)
(11)
361
5,440
4,052
9,492
— 4,951
— 3,729
— 8,679
—
—
—
—
—
—
—
454
33
122
355
(530)
(165)
269
— 4,941
— 4,008
— 8,949
561
299
860
507
272
779
10,014
7,797
17,810
10,381
8,060
18,441
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
At 31 December
Developed
Undeveloped
347
222
569
80
105
184
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 Excludes NGLs from processing plants in which an interest is held of less than 1 thousand barrels per day for subsidiaries and 2 thousand barrels per day for equity-accounted entities.
f Includes 31 million barrels of oil equivalent of natural gas consumed in operations, 23 million barrels of oil equivalent in subsidiaries, 8 million barrels of oil equivalent in equity-accounted
entities.
g Includes 335 million barrels of oil equivalent in respect of the 30% non-controlling interest in BP Trinidad and Tobago LLC.
h Volumes of equity-accounted entities include volumes of equity-accounted investments of those entities.
i Includes 391 million barrels of oil equivalent in respect of the non-controlling interest in Rosneft, including 34 mmboe held through BP’s equity-accounted interest in Taas-Yuryakh
Neftegazodobycha.
j Total proved reserves held as part of our equity interest in Rosneft is 7,864 million barrels of oil equivalent, comprising less than 1 million barrels of oil equivalent in Canada, 64 million barrels
of oil equivalent in Venezuela, 3 million barrels of oil equivalent in Vietnam, 41 million barrels of oil equivalent in Egypt and 7,755 million barrels of oil equivalent in Russia.
202
BP Annual Report and Form 20-F 2017
Movements in estimated net proved reserves – continued
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
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asiad
million barrels
2016
Total
141
298
440
13
—
3
2
(29)
—
(11)
155
274
429
—
—
—
—
—
—
—
—
—
—
—
—
—
141
298
440
86
19
106
—
—
—
—
(9)
(97)
(106)
890
577
1,467
46
205
252
(30)
1
3
—
(119)
(1)
(145)
—
—
—
4
(5)
—
(1)
—
826
497
—
— 1,322
42
209
251
—
—
—
—
—
116
—
(3)
—
114
45
69
114
86
19
106
—
—
—
—
—
—
—
—
—
—
—
—
—
890
577
1,467
826
497
1,322
—
—
—
—
—
—
—
—
—
—
—
—
—
47
205
252
42
209
251
8
18
26
(2)
—
—
—
(4)
—
(6)
9
11
20
311
311
622
(2)
1
36
16
(28)
—
24
321
325
646
319
329
648
330
336
666
340
89
429
22
3
—
—
(96)
—
(71)
317
42
358
—
—
—
—
—
—
—
—
—
—
598
192
790
543
70
25
—
(75)
(1)
562
— 1,107
245
—
— 1,352
2,844
2
— 1,981
4,825
2
—
—
—
—
—
—
—
33
4
456
285
(305)
(2)
471
1
3,162
— 2,134
5,296
1
68
—
68
13
—
—
—
(37)
(1)
(25)
43
1
44
342
89
431
318
42
360
2,844
1,981
4,825
3,162
2,134
5,296
666
192
858
1,150
246
1,395
35
16
51
2
—
1
—
(6)
(2)
(5)
32
14
46
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
35
16
51
32
14
46
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
At 31 December
Developed
Undeveloped
155
274
429
45
69
114
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.
BP Annual Report and Form 20-F 2017
203
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
million barrels
2016
Total
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
UK
5
4
10
7
—
1
—
(2)
—
7
13
3
16
—
—
—
—
—
—
—
—
—
—
—
—
—
Rest of
Europe
11
1
12
—
—
—
—
(1)
(10)
(12)
—
—
—
—
—
—
—
—
5
—
—
—
5
3
2
5
Rest of
North
America
Russia
Rest of
Asia
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
7
28
35
—
—
—
—
(2)
—
(2)
5
28
33
—
—
—
—
—
—
—
—
—
—
—
—
—
7
28
35
5
28
33
5
10
15
1
—
—
—
(2)
—
(1)
13
1
14
13
—
13
(2)
—
—
—
—
—
(2)
11
—
11
18
10
28
24
1
25
—
—
—
—
—
—
—
—
—
—
—
—
—
32
15
47
18
—
—
—
—
—
18
50
15
65
32
15
47
50
15
65
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
US
269
70
339
(24)
3
4
—
(24)
—
(40)
226
73
299
—
—
—
—
—
—
—
—
—
—
—
—
—
269
70
339
226
73
299
9
2
12
—
—
—
—
(1)
—
(1)
9
2
11
—
—
—
—
—
—
—
—
—
—
—
—
—
9
2
12
9
2
11
308
115
422
(14)
3
6
—
(34)
(10)
(49)
266
107
373
45
15
60
16
—
5
—
—
—
21
65
17
81
352
130
482
331
123
454
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
5
4
10
11
1
12
At 31 December
Developed
Undeveloped
13
3
16
3
2
5
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.
204
BP Annual Report and Form 20-F 2017
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
Total
UK
Rest of
Europe
USc
Rest of
North
America
Russia
Rest of
Asia
million barrels
2016
147
303
449
20
—
5
2
(31)
—
(4)
168
277
445
—
—
—
—
—
—
—
—
—
—
—
—
—
147
302
449
98
20
117
—
—
—
—
(10)
(108)
(117)
1,159
647
1,806
46
205
252
(54)
5
7
—
(143)
(1)
(185)
—
—
—
4
(5)
—
(1)
— 1,051
569
—
— 1,621
42
209
251
—
—
—
—
—
122
—
(3)
—
119
48
71
119
98
20
117
—
—
—
—
—
—
—
—
—
—
—
—
—
1,159
647
1,806
1,051
569
1,621
—
—
—
—
—
—
—
—
—
—
—
—
—
47
205
252
42
209
251
15
46
61
(2)
—
—
—
(6)
—
(8)
14
39
53
311
312
622
(2)
1
36
16
(28)
—
24
321
325
646
326
357
684
335
364
699
346
99
444
23
3
—
—
(98)
—
(72)
330
43
372
—
—
—
—
—
—
—
—
—
—
598
192
790
543
70
25
—
(75)
(1)
562
— 1,107
245
—
— 1,352
2,876
14
— 1,996
4,872
14
(2)
—
—
—
—
—
(2)
51
4
456
285
(305)
(2)
489
12
3,213
— 2,148
5,361
12
68
—
68
13
—
—
—
(37)
(1)
(25)
43
1
44
360
99
459
342
43
385
2,876
1,996
4,872
3,213
2,148
5,361
666
192
858
1,150
246
1,395
45
18
63
3
—
1
—
(7)
(2)
(5)
42
16
57
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
45
18
63
42
16
57
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
At 31 December
Developed
Undeveloped
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.
BP Annual Report and Form 20-F 2017
205
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
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
2016
Total
billion cubic feet
Russia
Rest of
Asia
348
343
691
133
—
95
—
(71)
—
158
499
350
848
—
—
—
—
—
—
—
—
—
—
—
—
—
348
343
691
274
14
288
—
—
—
—
(33)
(256)
(288)
6,257
2,105
8,363
(231)
469
91
1
(676)
(2)
(348)
— 2,071
— 5,989
— 8,060
847
2,305
3,152
— 1,803
— 3,455
— 5,257
3,408
1,343
4,751
15,009
15,553
30,563
(1,042)
3
42
—
—
—
355
—
(624)
(4)
—
(37)
— (1,306)
(19)
1
—
43
(219)
—
(194)
—
—
—
—
—
—
—
548
22
—
—
(152)
(17)
401
396
—
252
—
(306)
(439)
(97)
(211)
534
438
399
(2,085)
(750)
(1,675)
— 5,447
— 2,567
— 8,014
— 1,784
— 4,970
— 6,755
767
2,191
2,958
— 1,890
— 3,769
— 5,659
3,012
1,643
4,654
13,398
15,490
28,888
—
—
—
—
—
115
—
(4)
—
110
89
21
110
274
14
288
—
—
—
—
—
—
—
—
—
—
—
—
—
6,257
2,105
8,363
5,447
2,567
8,014
1
—
1
—
—
—
—
—
—
—
1,463
598
2,061
62
1
19
128
(190)
—
20
— 1,546
—
534
2,080
1
1
3,534
— 6,587
10,121
1
— 3,330
— 5,505
— 8,835
386
4,962
— 6,176
11,139
386
34
—
—
—
(8)
—
26
736
10
81
343
(461)
(1)
709
412
5,544
— 6,304
11,847
412
44
4
48
5
—
—
—
(15)
(8)
(18)
26
4
30
— 6,856
— 6,778
— 13,634
—
—
—
—
—
—
—
836
11
216
471
(680)
(8)
846
— 7,617
— 6,863
— 14,480
1,233
2,305
3,538
1,179
2,191
3,370
4,962
6,176
11,139
5,544
6,304
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
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
At 31 December
Developed
Undeveloped
499
350
848
89
21
110
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.
206
BP Annual Report and Form 20-F 2017
Movements in estimated net proved reserves – continued
Europe
North
America
South
America
UK
Rest of
Europe
USd
Rest of
North
America
million barrels of oil equivalentc
2016
Africa
Asia
Australasia
Total
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
145
22
167
—
—
—
—
(16)
(152)
(167)
2,238
1,010
3,248
46
205
252
373
1,078
1,451
(94)
86
23
—
(260)
(1)
(245)
1
—
—
4
(5)
—
(1)
(181)
7
—
61
(114)
(7)
(233)
— 1,990
— 1,012
— 3,002
42
209
251
321
896
1,217
492
496
988
20
3
—
8
(136)
—
(105)
462
420
882
Russia
Rest of
Asia
909
—
—
788
— 1,696
—
—
—
—
—
—
—
637
74
25
—
(101)
(4)
631
— 1,433
895
—
— 2,327
—
—
—
—
—
142
—
(3)
—
138
63
75
138
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
563
415
978
9
1
39
38
(61)
—
27
3,732
81
— 3,061
6,792
81
4
—
—
—
(2)
—
2
178
6
470
344
(385)
(2)
611
588
—
—
417
— 1,005
83
4,168
— 3,235
7,404
83
76
1
77
14
—
—
—
(40)
(2)
(28)
47
1
49
207
362
568
43
—
21
2
(43)
—
23
254
338
592
—
—
—
—
—
—
—
—
—
—
—
—
—
207
362
568
632
250
882
71
—
44
—
(60)
(78)
(22)
561
299
860
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
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
At 31 December
Developed
Undeveloped
254
338
592
63
75
138
145
22
167
2,238
1,010
3,248
1,990
1,012
3,002
47
205
252
42
209
251
936
1,493
2,429
909
1,313
2,222
573
496
1,069
545
420
966
3,732
3,061
6,792
4,168
3,235
7,404
984
788
1,773
1,480
896
2,376
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.
BP Annual Report and Form 20-F 2017
207
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
UK
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
2
—
—
—
(14)
—
(12)
86
19
106
—
—
—
—
—
—
—
—
—
—
—
—
—
1,030
664
1,694
(130)
15
—
3
(115)
—
(227)
890
577
1,467
—
—
—
—
—
—
—
—
—
—
—
—
—
1,030
664
1,694
890
577
1,467
9
163
172
39
—
—
42
(1)
—
80
46
205
252
—
—
1
—
—
—
—
—
—
—
—
—
—
9
164
173
47
205
252
10
22
32
(2)
—
—
—
(5)
—
(6)
8
18
26
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
—
—
—
—
—
—
—
—
—
—
—
—
—
2,997
2
— 1,933
4,930
2
—
—
—
—
—
—
—
(23)
—
28
185
(295)
(1)
(105)
2
2,844
— 1,981
4,825
2
319
120
439
342
89
431
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
—
68
473
208
682
666
192
858
40
19
59
(2)
—
—
—
(6)
—
(8)
35
16
51
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
40
19
59
35
16
51
5,448
3,796
9,244
5,371
3,707
9,078
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
159
329
488
95
22
117
At 31 December
Developed
Undeveloped
141
298
440
86
19
106
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.
208
BP Annual Report and Form 20-F 2017
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
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
Russia
Rest of
Asia
million barrels
2015
Total
6
3
9
2
—
—
—
(2)
—
—
5
4
10
—
—
—
—
—
—
—
—
—
—
—
—
—
13
1
14
—
—
—
—
(2)
—
(2)
11
1
12
—
—
—
—
—
—
—
—
—
—
—
—
—
323
104
427
(80)
12
3
—
(23)
(1)
(88)
269
70
339
—
—
—
—
—
—
—
—
—
—
—
—
—
323
104
427
269
70
339
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
11
28
39
—
—
—
—
(4)
—
(4)
7
28
35
—
—
—
—
—
—
—
—
—
—
—
—
—
11
28
39
7
28
35
5
7
12
6
—
—
—
(3)
—
3
5
10
15
15
—
15
(3)
—
—
—
—
—
(3)
13
—
13
20
7
27
18
10
28
—
—
—
—
—
—
—
—
—
—
—
—
—
30
16
46
1
—
—
—
—
—
1
32
15
47
30
16
46
32
15
47
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6
3
10
3
—
—
—
(1)
—
2
9
2
12
—
—
—
—
—
—
—
—
—
—
—
—
—
6
3
10
9
2
12
364
146
510
(69)
12
4
—
(34)
(1)
(88)
308
115
422
46
16
62
(2)
—
—
—
—
—
(2)
45
15
60
410
163
572
352
130
482
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
6
3
9
13
1
14
At 31 December
Developed
Undeveloped
5
4
10
11
1
12
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.
BP Annual Report and Form 20-F 2017
209
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
UK
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
2
—
—
—
(16)
—
(14)
98
20
117
—
—
—
—
—
—
—
—
—
—
—
—
—
1,352
769
2,121
(210)
28
3
4
(138)
(1)
(315)
1,159
647
1,806
—
—
—
—
—
—
—
—
—
—
—
—
—
1,352
769
2,121
1,159
647
1,806
9
163
172
39
—
—
42
(1)
—
80
46
205
252
—
—
1
—
—
—
—
—
—
(1)
—
—
—
9
164
173
47
205
252
21
50
71
(2)
—
—
—
(8)
—
(10)
15
46
61
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
—
—
—
—
—
—
—
—
—
—
—
—
—
3,028
17
— 1,949
4,976
17
(3)
—
—
—
—
—
(3)
(22)
—
28
185
(295)
(1)
(104)
14
2,876
— 1,996
4,872
14
339
127
466
360
99
459
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
—
68
473
208
682
666
192
858
46
22
68
1
—
—
—
(7)
—
(6)
45
18
63
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
46
22
68
45
18
63
5,858
3,958
9,817
5,723
3,836
9,560
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
166
332
497
108
23
131
At 31 December
Developed
Undeveloped
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 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.
210
BP Annual Report and Form 20-F 2017
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
UK
Rest of
Europe
North
America
South
America
Rest of
North
America
US
Africa
Asia
Australasia
2015
Total
billion cubic feet
Russia
Rest of
Asia
382
386
768
(12)
4
—
—
(65)
(5)
(77)
348
343
691
—
—
—
—
—
—
—
—
—
—
—
—
—
300
19
318
14
—
—
—
(44)
—
(30)
274
14
288
—
—
—
—
—
—
—
—
—
—
—
—
—
7,168
2,447
9,615
(1,120)
432
65
5
(628)
(6)
(1,252)
6,257
2,105
8,363
—
—
—
—
—
—
—
—
—
—
—
—
—
17
2,352
— 6,313
8,666
17
901
1,597
2,497
— 1,688
— 3,892
— 5,580
3,316
1,719
5,035
16,124
16,372
32,496
(13)
—
—
—
(4)
—
(17)
132
—
29
—
(709)
(58)
(605)
203
7
554
174
(248)
(35)
654
—
—
—
—
—
—
—
(165)
—
—
—
(157)
—
(322)
13
—
—
—
(297)
—
(284)
(948)
443
648
179
(2,151)
(104)
(1,933)
— 2,071
— 5,989
— 8,060
847
2,305
3,152
— 1,803
— 3,455
— 5,257
3,408
1,343
4,751
15,009
15,553
30,563
1
1
1
(1)
—
—
—
—
—
(1)
1
—
1
1,228
717
1,945
81
8
—
209
(182)
(1)
116
1,463
598
2,061
400
4,674
— 5,111
9,785
400
(14)
—
—
—
—
—
(14)
1,604
—
5
175
(430)
—
1,354
386
4,962
— 6,176
11,139
386
60
9
69
(2)
—
—
—
(19)
—
(21)
44
4
48
— 6,363
— 5,837
— 12,200
— 1,669
8
—
5
—
—
384
(632)
—
(1)
—
— 1,434
— 6,856
— 6,778
— 13,634
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
382
386
768
300
19
318
At 31 December
Developed
Undeveloped
348
343
691
274
14
288
7,168
2,447
9,615
6,257
2,105
8,363
18
1
18
3,581
7,030
10,610
1
3,534
— 6,587
10,121
1
1,301
1,597
2,897
1,233
2,305
3,538
4,674
5,111
9,785
4,962
6,176
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
22,487
22,209
44,695
21,865
22,331
44,197
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.
BP Annual Report and Form 20-F 2017
211
Movements in estimated net proved reserves – continued
Total hydrocarbonsa b
Subsidiaries
At 1 January
Developed
Undeveloped
Changes attributable to
Revisions of previous estimates
Improved recovery
Purchases of reserves-in-place
Discoveries and extensions
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
Europe
North
America
South
America
UK
Rest of
Europe
USd
Rest of
North
America
million barrels of oil equivalentc
2015
Africa
Asia
Australasia
Total
232
398
630
(22)
1
1
—
(40)
(1)
(62)
207
362
568
—
—
—
—
—
—
—
—
—
—
—
—
—
160
26
186
4
—
—
—
(23)
—
(19)
145
22
167
—
—
—
—
—
—
—
—
—
—
—
—
—
2,588
1,191
3,779
12
163
175
426
1,139
1,565
(403)
102
15
4
(247)
(2)
(531)
36
—
—
42
(2)
—
77
21
—
5
—
(130)
(10)
(114)
2,238
1,010
3,248
46
205
252
373
1,078
1,451
477
403
880
121
3
102
32
(144)
(6)
108
492
496
988
Russia
Rest of
Asiae
675
—
—
868
— 1,543
—
—
—
—
—
—
—
267
—
—
—
(114)
—
153
—
909
788
—
— 1,696
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
1
(1)
—
—
—
—
—
(1)
—
—
—
528
438
965
23
5
—
45
(60)
—
12
563
415
978
3,834
86
— 2,830
6,663
86
(5)
—
—
—
—
—
(5)
255
—
29
215
(369)
(1)
129
81
3,732
— 3,061
6,792
81
100
13
112
3
—
—
—
(39)
—
(36)
76
1
77
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
3,834
2,830
6,663
3,732
3,061
6,792
775
881
1,656
984
788
1,773
618
319
937
4
—
—
—
(58)
—
(55)
632
250
882
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
618
319
937
632
250
882
9,735
7,788
17,523
9,493
7,687
17,180
Total subsidiaries and equity-accounted entities (BP share)
At 1 January
Developed
Undeveloped
232
398
630
160
26
186
At 31 December
Developed
Undeveloped
207
362
568
145
22
167
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.
212
BP Annual Report and Form 20-F 2017
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
UK
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2017
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
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
26,300
13,800
1,700
4,200
6,600
2,100
— 99,200
— 46,700
— 12,100
— 6,500
— 33,900
— 13,100
7,100
4,100
1,100
15,200
7,100
2,400
— 1,700
4,000
500
1,900
1,100
27,000
8,600
3,400
3,800
11,200
3,400
— 118,800
— 52,600
— 18,200
— 33,200
— 14,800
5,500
—
26,200 319,800
8,400 141,300
42,100
3,200
54,200
4,800
82,200
9,800
30,500
4,800
4,500
— 20,800
800
3,500
7,800
—
9,300
5,000
51,700
— 9,000
— 4,100
—
800
— 3,100
— 1,000
400
—
—
600
—
—
—
—
—
—
—
— 32,900
— 15,500
— 3,400
— 3,100
— 10,900
— 6,400
— 205,100
— 114,900
— 17,600
— 12,400
— 60,200
— 34,900
— 4,500
— 25,300
400
300
100
—
—
—
—
— 247,400
— 134,800
— 21,900
— 18,600
— 72,100
— 41,700
— 30,400
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
future net cash flows
4,500
600
20,800
800
8,000
7,800
25,300
9,300
5,000
82,100
The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yearj
Subsidiaries
Equity-accounted
entities (BP share)
(12,800)
9,800
2,300
33,100
2,800
(12,500)
3,000
800
2,300
28,800
(5,500)
4,200
1,300
7,300
1,000
(1,500)
(4,600)
(600)
2,600
4,200
$ million
Total subsidiaries and
equity-accounted
entities
(18,300)
14,000
3,600
40,400
3,800
(14,000)
(1,600)
200
4,900
33,000
a The marker prices used were Brent $54.36/bbl, Henry Hub $2.96/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 $1,100 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 $1,963 million in Russia.
h No equity-accounted future cash flows in Africa because proved reserves are received as a result of contractual arrangements, with no associated costs.
i Total change in the standardized measure during the year includes the effect of exchange rate movements. Exchange rate effects arising from the translation of our share of Rosneft changes
to US dollars are included within ‘Net changes in prices and production cost’.
BP Annual Report and Form 20-F 2017
213
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and
gas reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2016
Total
21,600
13,900
3,000
1,700
3,000
900
— 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
— 78,100
— 42,600
— 15,400
— 17,800
— 2,300
(600)
—
24,000 235,900
9,400 129,100
46,100
3,500
25,500
3,400
35,200
7,700
12,300
4,100
2,100
— 9,600
(100)
1,100
3,700
— 2,900
3,600
22,900
— 5,400
— 3,000
—
700
— 1,300
400
—
200
—
—
200
—
—
—
—
—
—
—
— 34,400
— 16,500
— 3,800
— 3,600
— 10,500
— 6,100
— 159,900
— 84,300
— 13,200
— 10,100
— 52,300
— 30,700
1,900
1,200
700
—
—
—
— 201,600
— 105,000
— 18,400
— 15,000
— 63,200
— 37,000
— 4,400
— 21,600
—
— 26,200
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
Total subsidiaries and equity-accounted entities
Standardized measure of 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
Equity-accounted
entities (BP share)
(15,200)
13,100
700
(25,500)
12,200
(2,500)
4,900
1,800
3,000
(7,500)
(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 to US
dollars are included within ‘Net changes in prices and production cost’.
214
BP Annual Report and Form 20-F 2017
Standardized measure of discounted future net cash flows and changes therein relating to proved oil and
gas reserves – continued
Europe
North
America
South
America
Africa
Asia
Australasia
UK
Rest of
Europe
Rest of
North
America
US
Russia
Rest of
Asia
$ million
2015
Total
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
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
20,100
8,600
7,000
— 1,700
2,800
900
1,300
900
32,800
12,000
8,100
3,300
9,400
4,300
— 65,200
— 35,900
— 18,200
— 3,800
— 7,300
— 3,700
32,000 290,700
15,200 153,200
63,700
19,600
54,200
23,800
4,500
4,000
8,300
4,400
2,300
700
12,500
400
1,900
5,100
— 3,600
3,900
30,400
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
— 39,900
— 20,200
— 5,300
— 3,900
— 10,500
— 6,700
— 182,300
— 101,200
— 11,000
— 12,400
— 57,700
— 33,800
3,700
2,200
1,300
100
100
—
— 225,900
— 123,600
— 17,600
— 16,400
— 68,300
— 40,500
— 3,800
— 23,900
100
— 27,800
Total subsidiaries and equity-accounted entities
Standardized measure of discounted
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:
Sales and transfers of oil and gas produced, net of production costs
Development costs for the current year as estimated in previous year
Extensions, discoveries and improved recovery, less related costs
Net changes in prices and production cost
Revisions of previous reserves estimates
Net change in taxation
Future development costs
Net change in purchase and sales of reserves-in-place
Addition of 10% annual discount
Total change in the standardized measure during the yeari
Equity-accounted
entities (BP share)
(7,300)
4,500
700
(24,700)
500
2,300
(100)
300
4,700
(19,100)
$ million
Total subsidiaries and
equity-accounted
entities
(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’.
BP Annual Report and Form 20-F 2017
215
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 2017, 2016 and 2015.
Production for the yeara b
Europe
North
America
South
America
Africa
Asia
Australasia
Total
Subsidiariese
Crude oilf
2017
2016
2015
Natural gas liquids
2017
2016
2015
Natural gasg
2017
2016
2015
Equity-accounted entities (BP share)
Crude oilf
2017
2016
2015
Natural gas liquids
2017
2016
2015
Natural gasg
2017
2016
2015
UK
80
79
72
6
6
7
182
170
155
—
—
—
—
—
—
—
—
—
Rest of
Europe
—
24
38
—
4
5
—
82
111
31
7
—
2
—
—
53
12
—
US
370
335
323
56
56
56
1,659
1,656
1,528
—
—
—
—
—
—
—
—
—
Rest of
North
America
20
13
3
—
—
—
9
10
10
—
—
—
—
—
—
—
—
—
12
10
12
10
8
11
1,936
1,689
1,922
63
65
68
—
1
3
418
449
435
Russiac
—
—
—
—
—
—
—
—
—
905
840
809
4
4
4
1,308
1,279
1,195
241
263
270
10
5
7
949
513
589
1
—
—
6
4
3
77
18
—
Rest
of
Asiad
325
204
199
—
—
1
371
363
380
99
102
97
—
—
—
—
15
21
thousand barrels per day
17
16
17
1,064
943
933
thousand barrels per day
2
3
3
85
82
88
million cubic feet per day
783
820
801
5,889
5,302
5,495
thousand barrels per day
—
—
—
1,099
1,015
974
thousand barrels per day
—
—
—
12
8
10
million cubic feet per day
—
—
—
1,855
1,773
1,651
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.
216
BP Annual Report and Form 20-F 2017
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 2017. A ‘gross’
well or acre is one in which a whole or fractional working interest is owned, while the number of ‘net’ wells or acres is the sum of the whole or
fractional working interests in gross wells or acres. Productive wells are producing wells and wells capable of production. Developed acreage is
the acreage within the boundary of a field, on which development wells have been drilled, which could produce the reserves; while
undeveloped acres are those on which wells have not been drilled or completed to a point that would permit the production of commercial
quantities, whether or not such acres contain proved reserves.
Number of productive wells at 31 December 2017
Oil wellsc
Gas wellsd
Undevelopede
– gross
– net
– gross
– net
– gross
– net
– gross
– net
Oil and natural gas acreage at 31 December 2017
Developed
Europe
UK
Rest of
Europe
South
America
North
America
US
Rest of
North
America
130
78
76
34
132
75
2,553
1,586
47
14
1
—
70
21
1,361
517
2,365
817
23,376
9,841
6,467
3,446
5,179
3,780
166
41
268
133
157
71
15,139
7,200
5,145
2,337
982
347
1,322
351
23,358
7,082
Africa
Asia
Australasia
Totalb
Russiaa
62,492
12,342
478
94
693
466
194
82
789
310
43,211
27,841
6,393
1,211
425,477
84,724
Rest of
Asia
2,250
482
86
37
1,586
304
8,286
1,977
73,300
12
16,579
2
25,529
68
10,582
14
thousands of acres
173
41
5,584
2,116
17,089
5,830
530,148
136,823
a Based on information received from Rosneft as at 31 December 2017.
b Because of rounding, some totals may not exactly agree with the sum of their component parts.
c Includes approximately 8,890 gross (1,731 net) multiple completion wells (more than one formation producing into the same well bore).
d Includes approximately 2,827 gross (1,438 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
2017
Exploratory
Productive
Dry
Development
Productive
Dry
2016
Exploratory
Productive
Dry
Development
Productive
Dry
2015
Exploratory
Productive
Dry
Development
Productive
Dry
UK
Rest of
Europe
2.8
2.4
2.5
—
0.3
1.0
3.4
0.8
—
—
1.6
—
0.1
—
0.5
—
0.4
0.3
1.4
—
—
—
0.4
—
US
1.5
—
124.0
0.5
0.5
4.7
145.6
—
4.0
—
235.6
—
Rest of
North
America
Russia
Rest of
Asia
1.2
—
8.0
—
—
—
—
—
—
—
—
—
3.2
—
103.7
1.6
0.6
—
99.8
0.6
1.1
0.4
143.1
2.3
2.6
2.9
16.5
2.1
2.1
1.5
20.2
2.0
2.6
1.0
20.7
1.3
9.4
—
282.7
—
3.4
—
88.5
—
4.5
—
91.4
—
1.4
1.0
43.6
0.8
1.6
0.3
55.2
1.0
—
—
51.2
—
—
—
1.1
—
—
—
0.5
—
—
0.2
0.9
—
22.2
6.3
582.6
5.0
8.9
7.8
414.6
4.4
12.2
1.6
544.7
3.5
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
BP Annual Report and Form 20-F 2017
217
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 2017. 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 2017
Exploratory
Gross
Net
Development
Gross
Net
UK
1.0
0.3
6.0
2.3
Rest of
Europe
—
—
1.5
0.4
US
4.0
2.6
242.0
113.6
Rest of
North
America
Russia
Rest of
Asia
—
—
—
—
4.0
0.6
24.0
7.8
4.0
2.1
30.0
18.2
—
—
—
—
4.0
4.0
115.0
22.6
—
—
3.0
0.5
17.0
9.6
421.5
165.4
a Because of rounding, some totals may not exactly agree with the sum of their component parts.
218
BP Annual Report and Form 20-F 2017
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
2017
2
3
4
3
5
5
6
4
7
$ million
2016
166,283
2,951
528
169,762
487
50
537
170,299
166,276
2,623
3,838
172,737
293
10
303
173,040
7,903
4,225
34,104
1,337
221
35,662
43,565
129,475
104,498
2,145
(5,565)
101,078
5,343
12,147
10,907
129,475
34,432
179
219
34,830
39,055
131,244
111,521
(375)
(6,648)
104,498
5,284
12,219
9,243
131,244
a See Statement of changes in equity on page 220 for further information.
The financial statements on pages 219-245 were approved and signed by the group chief executive on 29 March 2018 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 219-245 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 2017
219
Company statement of changes in equitya
At 1 January 2017
Profit for the year
Other comprehensive income
Total comprehensive income
Dividends
Repurchases of ordinary share capital
Share-based payments, net of tax
At 31 December 2017
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
Share capital
Share
premium
account
Capital
redemption
reserve
5,284
—
—
—
72
(13)
—
5,343
5,049
—
—
—
137
98
5,284
12,219
—
—
—
(72)
—
—
12,147
10,234
—
—
—
(137)
2,122
12,219
1,413
—
—
—
—
13
—
1,426
1,413
—
—
—
—
—
1,413
Merger
reserve
26,509
—
—
—
—
—
—
26,509
26,509
—
—
—
—
—
26,509
$ million
Foreign
currency
translation
reserve
Profit and
loss account
Total equity
(236)
—
166
166
—
—
—
(70)
—
—
(236)
(236)
—
—
(236)
104,498
2,145
1,815
3,960
(6,153)
(343)
(884)
101,078
111,521
(375)
(1,269)
(1,644)
(4,611)
(768)
104,498
131,244
2,145
1,981
4,126
(6,153)
(343)
601
129,475
134,762
(375)
(1,505)
(1,880)
(4,611)
2,973
131,244
Treasury
shares
(18,443)
—
—
—
—
—
1,485
(16,958)
(19,964)
—
—
—
—
1,521
(18,443)
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 219-245 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
220
BP Annual Report and Form 20-F 2017
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 2017 were approved and signed by the group chief executive on
29 March 2018 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)
(c)
(d)
(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.
The 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 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 company are set out in boxed text below, and
should be read in conjunction with the information provided in the Notes on financial statements.
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. Where these circumstances have reversed, the impairment previously
made is reversed to the extent of the original cost of the investment.
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. Non-monetary assets and liabilities, other than those measured at fair value, are not
retranslated subsequent to initial recognition.
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 219-245 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 2017
221
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, 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
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.
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
Accounting for defined benefit pensions involves making significant estimates when measuring the company's pension plan surpluses and
deficits. These estimates require assumptions to be made about many uncertainties.
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.
The assumptions that are the most significant to the amounts reported are the discount rate, inflation rate, salary growth and mortality levels.
Assumptions about these variables are based on the environment in each country. The assumptions used vary from year to year, with
resultant effects on future net income and net assets. Changes to some of these assumptions, in particular the discount rate and inflation
rate, could result in material changes to the carrying amounts of the company’s pension obligations within the next financial year. Any
differences between these assumptions and the actual outcome will also affect future net income and net assets.
The values ascribed to these assumptions and a sensitivity analysis of the impact of changes in the assumptions on the benefit expense
and obligation used are provided in Note 4.
Income taxes
Income tax expense represents the sum of current tax and deferred tax.
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 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 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 taxable temporary differences.
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 219-245 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
222
BP Annual Report and Form 20-F 2017
1. Significant accounting policies, judgements, estimates and assumptions – continued
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.
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. The company derecognizes financial assets
when the contractual rights to the cash flows expire or the financial asset is transferred to a third party.
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, and when interest is recognized using the
effective interest method. 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 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 trade and other payables and finance debt.
2. Investments
Cost
At 1 January 2017
Disposals
Other movements
At 31 December 2017
Amounts provided
At 1 January 2017
Disposals
At 31 December 2017
Cost
At 1 January 2016
Additions
Disposals
At 31 December 2016
Amounts provided
At 1 January 2016
At 31 December 2016
At 31 December 2017
At 31 December 2016
Subsidiaries
Associates
Shares
Shares
Total
$ million
166,355
(41)
(7)
166,307
74
(41)
33
139,313
32,833
(5,791)
166,355
74
74
166,274
166,281
2
—
—
2
—
—
—
2
—
—
2
—
—
2
2
166,357
(41)
(7)
166,309
74
(41)
33
139,315
32,833
(5,791)
166,357
74
74
166,276
166,283
The more important subsidiaries of the company at 31 December 2017 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.
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
223
2. Investments – continued
Subsidiaries
International
BP Global Investments
BP International
Burmah Castrol
Canada
BP Holdings Canada
US
% Country of incorporation
Principal activities
100 England & Wales
100 England & Wales
100 Scotland
Investment holding
Integrated oil operations
Lubricants
100 England & Wales
Investment holding
BP Holdings North America
100 England & Wales
Investment holding
The carrying value of the investment in BP International Limited at 31 December 2017 was $76,152 million (2016 $76,152 million).
3. Receivables
Amounts receivable from subsidiariesa
Amounts receivable from associates
Other receivables
2017
$ million
2016
Current
Non-current
Current
Non-current
289
4
—
293
2,623
—
—
2,623
480
4
3
487
2,951
—
—
2,951
a Non-current receivables includes a promissory note issued by BP (Abu Dhabi) Limited in 2016 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 2017 the aggregate level of contributions was $509 million (2016 $539 million). The aggregate level of contributions in 2018 is
expected to be approximately $483 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 five years has been agreed. The funding agreement can be terminated unilaterally
by either party with two years’ notice. Contractually committed funding therefore represents seven years of future contributions, which
amounted to $2,623 million at 31 December 2017, of which $106 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 2017. 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, and a valuation as at 31 December 2017 is
currently under way.
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
2017
2.5
4.1
2.9
2.9
3.1
2017
2.7
2.7
3.2
%
2016
2.7
4.6
3.0
3.0
3.2
%
2016
4.0
3.9
3.1
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
4. Pensions – continued
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
deferred pensions.
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 an 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
2017
27.4
29.0
28.8
30.5
Years
2016
28.0
30.0
29.5
31.9
The assets of the primary plan are held in a trust, the primary objective of which is to accumulate assets sufficient to meet the obligations of
the plan. The assets of the trusts are invested in a manner consistent with fiduciary obligations and principles that reflect current practices in
portfolio management.
A significant proportion of the assets are held in equities, owing to a higher expected level of return over the long term of such assets with an
acceptable level of risk. In order to provide reasonable assurance that no single security or type of security has an unwarranted impact on the
total portfolio, the investment portfolios are highly diversified.
The trustee’s long-term investment objective for the primary UK plan as it matures is to invest in assets whose value changes in the same way
as the plan liabilities, in order to reduce the level of funding risk. To move towards this objective, the plan uses a liability driven investment (LDI)
approach for part of the portfolio, investing in government bonds to achieve this matching effect for the most significant plan liability assumptions
of interest rate and inflation rate. This is partly funded by short-term sale and repurchase agreements, whereby the plan borrows money using
existing bonds as security and which will be bought back at a specified price at an agreed future date. The funds raised are used to invest in further
bonds to increase the proportion of assets which match the plan liabilities. The borrowings are shown separately in the analysis of pension plan
assets in the table below.
The primary UK pension plan has an agreement with the trustee to increase the proportion of assets included in the LDI portfolio over time by
reducing the proportion of plan assets held as equities and increasing the proportion held as bonds. During 2017, the plan switched 15% of plan
assets from equities to bonds.
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
%
43
50
7
The amounts invested under the LDI programme by the primary UK pension plan as at 31 December 2017 were $2,588 million (2016 $423
million) of government-issued nominal bonds and $16,177 million (2016 $9,384 million) of index-linked bonds.
In addition, the primary plan has entered into interest rate swaps in the year to offset the long-term fixed interest rate exposure for $1,333
million (2016 $4,450 million) of the corporate bond portfolio. At 31 December 2017 the fair value liability of these swaps was $49 million (2016
$144 million fair value liability) and is included in other assets in the table below.
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 226.
Fair value of pension plan assets
Listed equities
- developed markets
- emerging markets
Private equitya
Government issued nominal bondsb
Government issued index-linked bondsb
Corporate bondsb
Propertyc
Cash
Other
Debt (repurchase agreements) used to fund liability driven investments
2017
9,548
2,220
2,679
2,663
16,177
4,682
2,211
390
104
(5,583)
35,091
$ million
2016
11,494
2,549
2,754
489
9,384
4,042
1,970
547
(68)
(2,981)
30,180
a Private equity is valued at fair value based on the most recent third-party net asset valuation.
b Bonds held are denominated in sterling.
c Property held is all located in the United Kingdom and are valued based on an analysis of recent market transactions supported by market knowledge derived from third-party valuers.
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
225
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
2017
357
12
369
31
400
845
(830)
15
2,396
(237)
734
91
2,984
$ million
2016
333
17
350
30
380
1,086
(1,004)
82
4,422
(6,926)
430
55
(2,019)
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
2017
29,871
2,882
369
830
16
(1,903)
(3)
(588)
31,474
30,180
3,048
845
16
509
(1,903)
2,396
35,091
3,617
3,838
(221)
3,617
3,838
(221)
3,617
$ million
2016
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
(31,253)
(221)
(31,474)
(29,661)
(210)
(29,871)
a Most of the contributions made by plan participants were made under salary sacrifice.
b The benefit payments amount shown above comprises $1,888 million benefits plus $18 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 $34,841 million of assets held in the BP Pension Fund (2016 $29,970 million) and $183 million held in the BP Global Pension Trust (2016 $165 million), with $53 million representing
the company’s share of Merchant Navy Officers Pension Fund (2016 $38 million) and $14 million of Merchant Navy Ratings Pension Fund (2016 $7 million).
e The fair value of plan assets includes borrowings related to the LDI programme as described on page 225.
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
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 2017 for the company’s plans would have had the effects
shown in the table below. The effects shown for the expense in 2018 comprise the total of current service cost and net finance income or
expense.
Discount ratea
Effect on pension expense in 2018
Effect on pension obligation at 31 December 2017
Inflation rateb
Effect on pension expense in 2018
Effect on pension obligation at 31 December 2017
Salary growth
Effect on pension expense in 2018
Effect on pension obligation at 31 December 2017
$ million
One percentage point
Increase
Decrease
(292)
(5,166)
185
4,316
50
578
241
6,789
(156)
(3,795)
(45)
(525)
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 2018 pension expense by $39 million and the pension
obligation at 31 December 2017 by $1,192 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 2027 and the
weighted average duration of the defined benefit obligations at 31 December 2017 are as follows:
Estimated future benefit payments
2018
2019
2020
2021
2022
2023-2027
Weighted average duration
5. Payables
Amounts payable to subsidiaries
Accruals and deferred income
Other payables
$ million
1,098
1,085
1,106
1,146
1,173
6,308
Years
19.8
$ million
2016
2017
Current
Non-current
Current
Non-current
7,770
60
73
7,903
34,055
—
49
34,104
3,904
129
192
4,225
34,389
43
—
34,432
Included in non-current amounts payable to subsidiaries is an interest-bearing payable of $4,236 million (2016 $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 $27,100 million (2016 $27,100 million) 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. Non-current amounts
payable to subsidiaries also includes an interest-bearing payable of $2,300 million (2016 $2,300 million) with BP Finance plc, with interest being
charged based on a 1-year USD LIBOR rate and a maturity date of April 2020.
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
2017
73
6,830
27,201
34,104
$ million
2016
206
6,936
27,290
34,432
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
227
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 (credit) for the year on ordinary activities
Charge (credit) for the year in other comprehensive income
At 31 December
2017
1,158
1,158
1,337
1,337
179
(11)
1,169
1,337
$ million
2016
(698)
(698)
179
179
877
52
(750)
179
At 31 December 2017, deferred tax assets of $92 million on other temporary differences and $8 million relating to pensions (2016 $82 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
Repurchase of ordinary share capital
At 31 December
Shares
thousand
7,233
5,473
21,049,696
289,789
—
(51,292)
21,288,193
2017
$ million
12
9
21
5,263
72
—
(13)
5,322
5,343
Shares
thousand
7,233
5,473
20,108,771
548,005
392,920
—
21,049,696
2016
$ million
12
9
21
5,028
137
98
—
5,263
5,284
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.
Voting on substantive resolutions tabled at a general meeting is on a poll. On a poll, shareholders present in person or by proxy have two votes
for every £5 in nominal amount of the first and second preference shares held and one vote for every ordinary share held. On a show-of-hands
vote on other resolutions (procedural matters) at a general meeting, shareholders present in person or by proxy have one vote each.
In the event of the winding up of the company, preference shareholders would be entitled to a sum equal to the capital paid up on the
preference shares, plus an amount in respect of accrued and unpaid dividends and a premium equal to the higher of (i) 10% of the capital paid
up on the preference shares and (ii) the excess of the average market price of such shares on the London Stock Exchange during the previous
six months over par value.
During 2017 the company repurchased 51 million ordinary shares at a cost of $343 million, including transaction costs of $2 million, as part of
the share repurchase programme announced on 31 October 2017. All shares purchased were for cancellation. The repurchased shares
represented 0.2% of ordinary share capital.
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
7. Called-up share capital – continued
Treasury sharesa
At 1 January
Purchases for settlement of employee share plans
Shares re-issued for employee share-based payment plansb
At 31 December
Of which - shares held in treasury by BP
- shares held in ESOP trusts
- shares held by BP’s US plan administratorc
Shares
thousand
1,614,657
4,423
(137,008)
1,482,072
1,472,343
9,705
24
2017
Nominal value
$ million
403
1
(34)
370
368
2
—
Shares
thousand
1,756,327
9,631
(151,301)
1,614,657
1,576,411
21,432
16,814
2016
Nominal value
$ million
439
2
(38)
403
394
5
4
a See Note 8 for definition of treasury shares.
b A minor amendment has been made to the number of shares re-issued for employee share-based payment plans in 2016.
c 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 7.5% (2016 8.6%) of the called-up ordinary share capital of the company.
During 2017, the movement in shares held in treasury by BP represented less than 0.5% (2016 less than 0.8%) of the ordinary share capital of
the company.
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.
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 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 (2016 $24,107 million), the distribution of which is limited by statutory or other
restrictions.
The financial statements for the year ended 31 December 2017 do not reflect the dividend announced on 6 February 2018 and paid in March
2018; this will be treated as an appropriation of profit in the year ended 31 December 2018.
9. Financial guarantees
The company has issued guarantees under which the maximum aggregate liabilities at 31 December 2017 were $75,824 million (2016 $71,443
million), the majority of which relate to finance debt of subsidiaries. Also included are 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.
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
229
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
2017
397
9
406
54
58
$ million
2016
397
44
441
59
48
In 2016, 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 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 9 to the consolidated financial statements.
11. Auditor’s remuneration
Note 34 to the consolidated financial statements provides details of the remuneration of the company’s auditor on a group basis.
12. Directors’ remuneration
Remuneration of directors
Total for all directors
Emoluments
Amounts awarded under incentive schemesa
Total
a Excludes amounts relating to past directors.
2017
9
9
18
$ million
2016
10
14
24
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. Further information is provided in the Directors’
remuneration report on page 90.
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
2017
496
74
92
662
2017
262
1,125
2,384
3,771
$ million
2016
480
66
69
615
2016
248
1,152
2,405
3,805
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
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 2017 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. (99.90%)
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 Iceland
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
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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
Öljytie 4, 01530 Vantaa, Finland
Armula 24, 108, Reykjavik, Iceland
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
P.O. Box, 153 Skoyen, Oslo, 0212, Norway
59 Aurel Vlaicu Street, Otopeni, Ilfov County, Romania
Box 8107, 10420, Stockholm, Sweden
398 Tingira Street, Pinkenba QLD 4008, 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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
231
14. Related undertakings of the group – continued
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
Amoco U.K. Petroleum Limited
AmProp Finance Company
Amprop Illinois I Limited Partnershipg
Amprop, Inc.
Anaconda Arizona, Inc.
Arabian Production And Marketing Lubricants
Company (50.00%)
Aral Aktiengesellschaft
Aral Luxembourg S.A.
Aral Services Luxembourg Sarl
Aral Tankstellen Services Sarl
Aral Vertrieb GmbH
ARCO British International, Inc.
ARCO British Limited, LLCa
ARCO Coal Australia Inc.
ARCO El-Djazair Holdings Inc.
ARCO El-Djazair LLC
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
ARCO Unimar Holdings LLCa
Aspac Lubricants (Malaysia) Sdn. Bhd. (63.03%)
Atlantic 2/3 UK Holdings Limited
Atlantic Richfield Company
Autino Holdings Limited (90.73%)h
Autino Limited (90.73%)
Auwahi Wind Energy Holdings LLCa
B2Mobility GmbH
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 Limiteda
BP (China) Industrial Lubricants Limiteda
BP (Gibraltar) Limitedj
BP (Indian Agencies) Limitedi
BP (Malta) Limited (in liquidation)i
BP (Shandong) Petroleum Co., Ltda
BP (Shanghai) Trading Limiteda
BP Absheron Limited
BP Africa Limitedi
BP Akaryakit Ortakligi (70.00%)g
BP Alaska LNG LLCa
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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
Riyadh Airport Road, Business Gate, Building C2, 2nd Floor., Saudi Arabia
Wittener Straße 45, 44789 Bochum, Germany
Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg
Autoroute A3/E25, L-3325 Brechem Ouest, Luxembourg
Bâtiment B, 36route de Longwy, L-8080 Bertrange, Luxembourg
Überseeallee 1, 20457, Hamburg, 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
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
Providence House, East Hill Street, P.O. Box N-3944, Nassau, Bahamas
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 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
83-85 London Street , Reading , Berkshire, RG1 4QA, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Wittener Straße 45, 44789 Bochum, Germany
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 1-2201, Sijian Meilin Mansion, No. 48-15 Wuyingshan Middle Road, Tianqiao District, Ji'nan,
Shandong, China
No. 28 Maji Road, Donghua Financial Building, China (Shanghai) Pilot Free Trade, 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 İcerenkoy-Atasehir, Istanbul, 34752, Turkey
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
The parent company financial statements of BP p.l.c. on pages 219-245 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
232
BP Annual Report and Form 20-F 2017
14. Related undertakings of the group – continued
BP Alternative Energy Holdings Limited
BP Alternative Energy Investments 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 Argentina Holdings LLCa
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
BP Berau Ltd.
BP Biocombustíveis S.A. (99.96%)
BP Bioenergia Campina Verde Ltda. (99.96%)
BP Bioenergia Ituiutaba Ltda. (99.96%)
BP Bioenergia Itumbiara S.A. (99.96%)
BP Bioenergia Tropical S.A. (99.97%)
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. (99.96%)
BP Bomberai Ltd.
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 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 Investments Limited
BP Chemicals Limited
BP Chemicals Trading Limited (In Liquidation)
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
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
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
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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
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
Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida das Nações Unidas, 12399, 4fl, Sao 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
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
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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
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
Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 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
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
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
233
14. Related undertakings of the group – continued
BP Chile Petrolera Limitada
BP China Exploration and Production Company
BP China Limited (In Liquidation)i
BP Commodities Trading Limited
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.
BP Danmark A/S
BP D-B Pipeline Company LLCa
BP Developments Australia Pty. Ltd.
BP Dogal Gaz Ticaret Anonim Sirketi
BP East Kalimantan CBM Limited
BP Eastern Mediterranean Limited
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 Estaciones y Servicios Energéticos, Sociedad
Anónima de Capital Variablec
BP Europa SEm
BP Exploracion de Venezuela S.A.
BP Exploration & Production Inc.e
BP Exploration (Absheron) Limited
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 (In Liquidation)
BP Exploration (Greenland) Limited
BP Exploration (Madagascar) 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
BP Exploration (South Atlantic) Limited
BP Exploration (Vietnam) Limited (In Liquidation)
BP Exploration (Xazar) PTE. Limited
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 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
Patricio Raby Benavente, Moneda N° 920 Of 205, Santiago, Chile
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
55 Baker Street, London, W1U 7EU, 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
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Level 8, 250 St Georges Terrace, Perth WA 6000, Australia
Degirmen yolu cad. No:28, Asia OfisPark K:3 İcerenkoy-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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, 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
Avenida Santa Fe 505, Piso 10, Distrito Federal, Mexico C.P. 0534, Mexico
Überseeallee 1, 20457, Hamburg, 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
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
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
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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, 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
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
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, 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
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
14. Related undertakings of the group – continued
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 Ghana Limited
BP Global Investments Limitedi
BP Global Investments Salalah & Co LLC
BP Global West Africa Limited
BP GOM Logistics LLCa
BP Greece Limited
BP Guangdong Limited (90.00%)a
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 Limited
BP India Services Private Limited
BP Indonesia 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 Mariner Holding Company LLCa
BP Maritime Services (Isle of Man) Limited
BP Maritime Services (Singapore) Pte. Limited
BP Marketing Egypt LLC
BP Mauritania Investments Limited
BP Mauritius Limited
BP Middle East Enterprises Corporation
BP Middle East Limitedi
BP Middle East LLC
BP Midstream Partners GP LLCa
BP Midstream Partners Holdings LLCa
BP Midstream Partners LPg
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 Nutrition Inc.
BP Offshore Gathering Systems Inc.
BP Offshore Pipelines Company LLCa
BP Offshore Response Company LLCa
BP Oil (Thailand) Limited (90.32%)p
BP Oil and Chemicals International Philippines Inc.
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
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
Heritage Place, 7th Floor, Left Wing, 21 Lugard Avenue, Ikoyi, Lagos, Nigeria
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
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
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 Verona 12, Cornaredo, 20010, 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
Clarendon House, 2 Church Street, P.O. Box HM 1022, Hamilton, HM DX, Bermuda
Überseeallee 1, 20457, Hamburg, 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
Tower 5, Avenue 7, The Horizon Bangsar South City, No. 8, Jalan Kerinchi, 59200 Kuala Lumpur, Malaysia
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Samuel Harris House, 5-11 St Georges Street, Douglas, Isle of Man, IM1 1AJ, Isle of Man
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, Singapore
Plot 28, North 90 Road, Housing & Construction Bank Building, New Cairo, Cairo, 11835, Egypt
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
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
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
Society and Geography Avenue, Plot No. 269 , Third floor, Maputo, Mozambique
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
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
39/77-78 Moo 2 Rama II Road, Tambon Bangkrachao, Amphur Muang, Samutsakorn 74000, Thailand
30/F LKGTower, 6801 Ayala Avenue, Makati City 1226, Philippines
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
235
14. Related undertakings of the group – continued
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 (24.89%)
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 River Rouge Pipeline Company LLCa
BP Russian Investments Limited
BP SC Holdings LLCa
BP Senegal Investments Limited
BP Services International Limited
BP Servicios de combustibles SA de CV
BP Servicios territoriales, S.A. de C.V.
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 Limited
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 Two Pipeline Company LLCa
BP Venezuela Investments B.V.
BP West Aru I Limited
Level 17, 717 Bourke Street, Docklands VIC, Australia
Polígono Industrial "El Serrallo", s/n 12100 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, 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 OfisPark K:3 İcerenkoy-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
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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, Mexico
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
7 Straits View #26-01, Marina One East Tower, Singapore, 018936, 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, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
14. Related undertakings of the group – continued
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%)a
BP+Amoco International Limitedi
BPA Investment Holding Company
BP-AIOC Exploration (TISA) LLC (70.84%)a
BPNE International B.V.
BPRY Caribbean Ventures LLC (70.00%)a
BPX Energy Inc.
Brian Jasper Nominees Pty Ltd
Britannic Energy Trading Limited
Britannic Investments Iraq Limited (90.00%)
Britannic Marketing Limited
Britannic Strategies Limited
Britannic Trading Limited
British Pipeline Agency Limited (50.00%)b q
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 Limiteda
Castrol (Tianjin) Lubricants Co., Ltda
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. LLC "u.d." (Castrol
Hungária Kereskedelmi Kft. "v.a.")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. (v likvidaci)a
Castrol Lubricants RO S.R.L
Castrol Mexico, S.A. de C.V.c
Castrol Namibia (Pty) Limited
Castrol Offshore Limited
Castrol Pakistan (Private) Limited
Castrol Philippines, Inc.
Castrol Servicos Ltda.
Castrol Slovensko, s.r.o. (v likvidácii)a
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.
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
153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
RL&F Service Corp, 920 North King Street, 2nd Floor, Wilmington DE 19801, United States
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
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
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
2 Grand Canal Square, Dublin 2, Dublin, Ireland
No.1120 Mawan Road, Nanshan District, China
Tianjin Economic Development Area, 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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
KR 7 NO. 74 09, Bogota D.C., Colombia
Av. Camino Real, 111 Torre B Oficina, 603 San Isidro, Lima, Peru
32-34 Soroksári út, Budapest, 1095, 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
Na strži 1702/65, 14800 Praha 4 Nusle, Czech Republic
5th Floor, 92-96 Izvor St, 5th District, Bucharest, Romania
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, 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, Karachi, Pakistan
32/F LKG Tower, Ayala Avenue, Makati City, 6801, Philippines
Avenida Tamboré, 448, Barueri, Sao Paulo, Brazil
Rožnavská 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
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
237
14. Related undertakings of the group – continued
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%)
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
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.
Fuel & Retail Aviation Sweden AB
FUELPLANE- Sociedade Abastecedora de Aeronaves,
Unipessoal, Lda
FWK (2017) Limitedt
FWK Holdings (2017) LTDt
Gardena Holdings Inc.
Gasolin GmbH
GOAM 1 C.I S. A .S
Grampian Aviation Fuelling Services Limited
Guangdong Investments Limited
Highlands Ethanol, LLCa
Hydrogen Energy International Limited
IGI Resources, Inc.
Insight Analytics Solutions Holdings Limited (74.50%)
Insight Analytics Solutions Limited (74.50%)
Insight Analytics Solutions USA, Inc (74.50%)
International Bunker Supplies Pty Ltd
International Card Centre Limited
Iraq Petroleum Company Limited
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 Transportation System Company LLCa
Markoil, S.A. Unipersonal
Masana Petroleum Solutions (Pty) Ltd (37.88%)
Mayaro Initiative for Private Enterprise Development
(70.00%)a
Mehoopany Holdings LLCa
Mes Tecnologia en Servicios y Energia, S.A. DE C.V.
(99.92%)c
Minza Pty. Ltd.
Mountain City Remediation, LLCa
No. 1 Riverside Quay Proprietary Limited
Nordic Lubricants A/S
Nordic Lubricants AB
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 - 4th 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
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
112 SW 7th Street, Suite 3C, Topeka, Kansas, 66603, United States
Avenida Eliodoro Yañez N° 1572, Providencia , Santiago, Chile, Chile
d'Arcyweg 76, 3198 NA Europoort Rotterdam, 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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Box 8107, 10420, Stockholm, Sweden
Lagoas Park, Edificio 3, Porto Salvo, Oeiras, Portugal
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
Chertsey Road , Sunbury on Thames , TW16 7BP, United Kingdom
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Wittener Straße 45, 44789 Bochum, Germany
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
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
Romax Technology Centre , University of Nottingham Innovation Park, Triumph Road, Nottingham, NG7
2TU, United Kingdom
Romax Technology Centre , University of Nottingham Innovation Park, Triumph Road, Nottingham, NG7
2TU, United Kingdom
2108 55th Street, Suite 105, Boulder CO 80301, 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
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 -5814c/o Coral Oil Building, 583Avenue 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
Avenida de Barajas 30, Parque Empresarial Omega, Edificio D. 28108 Alcobendas, Madrid, Spain
BP House, 10 Junction Avenue, Parktown, Johannesburg, 2193, South Africa
5-5A Queen's Park West, Port-of-Spain, Trinidad and Tobago
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Avenida Santa Fe 505, Col. Cruz Manca Santa Fe, Delegacion Cuajimalpa, 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
Hemvärnsgatan , 171 54, Solna, Sweden
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
14. Related undertakings of the group – continued
Teknobulevardi 3-5, 01530 Vantaa, Finland
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
111 Eighth Avenue, New York, New York, 10011, United States
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
Novinskiy blvd.8, 17th floor, office 11, 121099, Moscow, Russian Federation
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
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
Nordic Lubricants Oy (in liquidation)
North America Funding Company
Oelwerke Julius Schindler GmbH
OMD87, Inc.
Omega Oil Company
OnSight Analytics Solutions India Private Ltd. (74.50%) #11, Platinum Tower, Ground Floor, Old Trunk Road, Pallavaram Chennai, India
OOO BP STLa
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
Peaks America Inc.
Pearl River Delta Investments Limited
Phoenix Petroleum Services, Limited Liability
Company
Products Cogeneration Company
Produits Métallurgie Doittau SA - PROMEDO
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
Romax Insight Korea Limited (74.50%)
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
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, Jakarta12520, Indonesia
Perkantoran Hijau Arkadia, Tower B, Jl. Let. Jenderal TB. Simatupang Kav. 88, Jakarta12520, 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
504 Cheong dan ro-213-3, Young pyung dong 2170-1 Jeju Science Park Smart Building, Jeju City, Jeju-do,
Korea, Republic of
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
4 High Street, Alton, Hampshire, GU34 1BU, United Kingdom
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
400 Cornerstone Drive, Suite 240, Williston VT 05495, United States
2 Paveletskaya sq, Building1, 115054 Moscow, Russian Federation
98 Panfilov Street, office 809, Almaty, 05000, Kazakhstan
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
251 East Ohio Street, Suite 500, Indianapolis IN 46204, United States
Level 17, 717 Bourke Street, Docklands VIC, Australia
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
4400 Easton Commons Way , Suite 125, Columbus OH 43219, United States
153 Neftchilar Avenue, Baku, AZ1010, Azerbaijan
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
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
33 North LaSalle Street, Chicago, Illinois 60602, United States
Ropemaker Deansgate Limited
Ropemaker Properties Limited
Ruehl Gesellschaft m.b.H. & Co KG.g
Ruhr Oel GmbH (ROG)
Rural Fuel Limited (49.00%)
Rusdene GSS Limitedt
Saltend Chemicals Park Limited
Saturn Insurance Inc.
Setra Lubricantsa
Setra Lubricants Kazakhstan LLPg
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%)u
Southeast Texas Biofuels LLCa
Southern Ridge Pipeline Holding Company
Southern Ridge Pipeline LP LLCa
Sp/f Decision3 (GreenSteam) Company (61.68%)v
SRHP (99.99%)a
Standard Oil Company, Inc.
Taradadis Pty. Ltd.
Telcom General Corporation (99.96%)e
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
TISA Education Complex LLC (70.84%)a
TJKK
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.
Viceroy Investments Limited
Warrenville Development Limited Partnershipa
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
239
14. Related undertakings of the group – continued
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
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
d'Arcyweg 76, 3198 NA Europoort Rotterdam, Netherlands
Jayla Place, Wickhams Cay 1, PO Box 3190, Road Town, Tortola, VG1110, British Virgin Islands
The parent company financial statements of BP p.l.c. on pages 219-245 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
240
BP Annual Report and Form 20-F 2017
14. Related undertakings of the group – continued
Related undertakings other than subsidiaries
Berghausener Straße 96, 40764 Langenfeld, Germany
Box 135, 190 46 Arlanda, Sweden
Brucknerstraße 4, 1041 Wien, Austria
Chertsey Road, Sunbury on Thames, Middlesex, TW16 7BP, United Kingdom
18010 Skypark Circle , #130 , Irvine CA 92614, United States
Berghausener Straße 96, 40764 Langenfeld, Germany
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
Level 12, 680 George Street, Sydney NSW 2000, 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
A Flygbranslehantering AB (AFAB) (25.00%)
ABG Autobahn-Betriebe GmbH (32.58%)a
Abu Dhabi Marine Areas Limited (33.33%)b
Advanced Biocatalytics Corporation (24.20%)w
AGES International GmbH & Co. KG, Langenfeld
(24.70%)g
AGES Maut System GmbH & Co. KG, Langenfeld
(24.70%)g
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%) Yakuplu Mahallesi Genc, Osman Caddesi, No.7 Beylikdüzü, Istanbul, Turkey
Ammenn GmbH (75.00%)
ARCO Solar Nigeria Ltd. (40.00%)
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%)
Axion Comercializacion de Combustibles y
Lubricantes S.A. (50.00%)
Axion Energy Argentina S.A. (50.00%)
Axion Energy Holding S.L. (50.00%)a
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
7M8 Ligali Ayorinde Street, Victoria Island, Lagos, Nigeria
Degirmen yolu cad. No:28, Asia OfisPark K:3 İcerenkoy-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
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
Luis A de Herrera 1248, Torre II, Piso 22 (Edificio World Trade Center), Montevideo, Uruguay
Maracaibo Drive, Point Lisas Industrial Estate, Point Lisas, Trinidad and Tobago
Building 1, 747 Lytton Road, Murarrie QLD 4172, 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
Level 3, Unit 3, 22 Albert Road, South Melbourne VIC 3205, Australia
Carlos María Della Paolera 265, Piso 22, Ciudad Autónoma de Buenos Aires, Argentina
Campus Empresarial Arbea - Edificio No 1, Carretera Fuencarral a Alcobendas, Alcobendas, Madrid,
Spain
Av. España 1369 esquina San Rafael, Asunción, Paraguay
Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay
Avenida Luis Alberto de Herrera 1248, Oficina 1901, Montevideo, Uruguay
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, 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
Sportallee 6, 22335 Hamburg, Germany
Axion Energy Paraguay S.R.L. (50.00%)a
Axuy Energy Holdings S.R.L. (50.00%)a
Axuy Energy Investments S.R.L. (50.00%)a
Azerbaijan Gas Supply Company Limited (23.06%)b
Azerbaijan International Operating Company (40.50%)x 190 Elgin Avenue, George Town, Grand Cayman , KY1-9005, Cayman Islands
Baplor S.A. (50.00%)
Barranca Sur Minera S.A. (50.00%)
Bayernoil Raffineriegesellschaft mbH (35.00%)
Beer GmbH (50.00%)
Beer GmbH & Co. Mineralol-Vertriebs-KG (50.00%)g
BGFH Betankungs-Gesellschaft Frankfurt-Hahn GbR
(50.00%)g
Billund Refuelling I/S (50.00%)
Blendcor (Pty) Limited (37.50%)s
Blue Marble Holdings Limited (23.58%)y
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%)a
BP PetroChina Petroleum Co., Ltd (49.00%)a
BP PETRONAS Acetyls Sdn. Bhd. (70.00%)
BP Sinopec (ZheJiang) Petroleum Co., Ltd (40.00%)
a
GA Centervej 1, DK-7190, Billund, Denmark
135 Honshu Road, Islandview, Durban, 4052, South Africa
Desklodge - 5th Floor, 1 Temple Way, Bristol, BS2 0BY, United Kingdom
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
P.O.Box 20302/211, 20302, Oman
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
No.13 Longxue Road, Longxue Island, Nansha District, Guangzhou, Guangdong, 511450, China
Room A17th 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
BP Sinopec Marine Fuels Pte. Ltd. (50.00%)
BP West Africa Supply Limited (50.00%)
BP YPC Acetyls Company (Nanjing) Limited
(50.00%)a
BP-Husky Refining LLC (50.00%)a
BP-Japan Oil Development Company Limited
(50.00%)b
112 Robinson Road, #05-01, Robinson 112, 068902, Singapore
Number 1, Rehoboth Place, Dade Street, North Labone Estates, Accra, Accra Metropolitan, Greater
Accra, P. O. BOX CT3278, Ghana
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
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
241
14. Related undertakings of the group – continued
8 Temasek Boulevard #31-02, Suntec City Tower 3, Singapore 038988, Singapore
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
Københavns, Lufthavn, 2770 Kastrup, Denmark
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
680 George Street, Sydney NSW 2000, Australia
6400 Shafer Ct., Suite 400, Rosemont IL 60018-4927, United States
30600 Telegraph Road, Suite 2345, Bingham Farms MI 48025, 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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Block 1Tendeseka Office Park, Samora Machel Av/Renfrew Road, Harare, Zimbabwe
800 S. Gay Street, Suite 2021, Knoxville TN 37929, United States
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
6th Floor, No. 413 Section 2 Ruei Kuang Road, Neihhu, Taipei, 11493, Taiwan
San Gottardo Sud, 6780, Airolo, Switzerland
Wittener Straße 45, 44789 Bochum, Germany
Kastrup Lufthavn, 2770 Kastrup, Denmark
Kastrup Lufthavn, 2770 Kastrup, Denmark
La Cumparsita 1373, piso 4°, Montevideo, Uruguay
Westfalendamm 166, 44141 Dortmund, Germany
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
Braendstoflageret Kobenhavns Lufthavn I/S (20.83%)
BTC International Investment Co. (30.10%)z
Butamax™ Advanced Biofuels LLC (50.00%)a
Caesar Oil Pipeline Company, LLC (56.00%)a
Cairns Airport Refuelling Service Pty Ltd (33.33%)
Cantera K-3 Limited Partnership (39.00%)g
Canton Renewables, LLC (50.00%)a
Castrol Cuba S.A. (50.00%)
Castrol DongFeng Lubricant Co., Ltd (50.00%)a
Cedar Creek II Holdings LLC (50.00%)a
Cedar Creek II, LLC (50.00%)a
CEFARI RNG OKC, LLC (50.00%)a
Cekisan Depolama Hizmetleri Limited Sirketi (35.00%) Yakuplu Ambarli Mevkii, 9 Ada2-3-6-7 Parsel, Büyükçekmece, Istanbul, Turkey
Central African Petroleum Refineries (Pvt) Ltd
CERF Shelby, LLC (50.00%)a
Chicap Pipe Line Company (56.17%)a
China American Petrochemical Company, Ltd.
(CAPCO) (61.36%)
China Aviation Oil (Singapore) Corporation Ltd
Clean Eagle RNG, LLC (50.00%)a
Cleopatra Gas Gathering Company, LLC (53.00%)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%)
Danish Refuelling Service I/S (33.33%)g
Danish Tankage Services I/S (50.00%)g
Dinarel S.A. (20.00%)
DOPARK GmbH (25.00%)
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 (65.00%)a
Energenomics LLC (50.00%)a
Energy Emerging Investments, LLC (50.00%)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
Field Services Enterprise S.A. (50.00%)
Finite Carbon, Inc. (50.00%)
Finite Resources, Inc. (50.00%)
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. (50.00%)
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
Av. Leandro N. Alem 1180, piso 11, Buenos Aires, Argentina
2711 Centerville Road, Suite 400, Wilmington, County of New Castle, Delaware 19808
2711 Centerville Road, Suite 400, Wilmington, County of New Castle, Delaware 19808
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
Radlpaßstraße 6, 8502 Lannach, Austria
Schillerstraße 10, 66482 Zweibrücken, Germany
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
Lennujaama tee 2, Tallinn EE0011, Estonia
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
Postboks 133, Gardermoen, NO-2061, Norway
Colonia 810, Oficina 403, Montevideo, Uruguay
P.O.Box 261781, Dubai, United Arab Emirates
Plot No. B003R04, Box No. 9400, Dubai, United Arab Emirates, 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
Überseeallee 1, 20457, Hamburg, Hamburg, Germany
Bertrand-Russell-Straße 3, 22761 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
The parent company financial statements of BP p.l.c. on pages 219-245 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
242
BP Annual Report and Form 20-F 2017
14. Related undertakings of the group – continued
Georg Reitberger Mineralöle Verwaltungs GmbH
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
Guangdong Dapeng LNG Company Limited
(30.00%)a
Gulf Of Suez Petroleum Company
"GUPCO" (50.00%)
GVÖ Gebinde-Verwertungsgesellschaft der
Mineralölwirtschaft mbH (21.00%)
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. (50.00%)
Hokchi Iberica S.L. (50.00%)
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
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
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
2-2 Sangnam-ri, Chungryang-myun, Ulju-gun, Ulsan 689-863, Republic of Korea
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Moezelweg 101, 3198LS Europoort, Rotterdam, Netherlands
Naz City, Building J, Suite 10 Erbil, Iraq
C/O Banks Cooper Associates, 21 Marina Court, Hull, HU1 1TJ, United Kingdom
An der Braker Bahn 22, 26122 Oldenburg, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
An der Braker Bahn 22, 26122 Oldenburg, Germany
6th Floor, 65 Gresham Street, London, England and Wales, EC2V 7NQ, United Kingdom
Luisenstraße 5 a, 26382 Wilhelmshaven, Germany
Sportallee 6, 22335 Hamburg, Germany
Pervomayskaya street, 32A, 678144, Lensk, Sakha (Yakutiya) Republic, Russian Federation
Grunwaldzka 472B, 80-309, Gdansk, Poland
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 PCJ Building36 Trafalgar Road, Kingston 10, Jamaica
Kingston Research Limited (50.00%)
Klaus Köhn GmbH (50.00%)
KM Phoenix Holdings LLC (25.00%)a
Köhn & Plambeck GmbH & Co. KG (50.00%)g
Kosmos Energy Investments Senegal Limited
(49.99%)b
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 ograniczoną
odpowiedzialnością (50.00%)
LOTTE BP Chemical Co., Ltd (50.94%)
Maasvlakte Europoort Pipeline Maatschap (50.00%)g
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
Manpetrol S.A. (50.00%)
Mars Oil Pipeline Company LLC (28.50%)a
Masana Employee Share Trust No. 1 (37.88%)a
MATELUB S.A.R.L. (Baldersheim/Frankreich) (80.00%) 20 Rue Contades, 67300, Schiltigheim, France
Mavrix, LLC (50.00%)a
McFall Fuel Limited (49.00%)
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)
(44.40%)
Natural Gas Vehicles Company "NGVC" (40.00%)
New Zealand Oil Services Limited (50.00%)
Newshelf 1310 (RF) Proprietary Limited (37.88%)
NFX Combustíveis Marítimos Ltda. (50.00%)
Nord-West Oelleitung GmbH (59.33%)
North Ghara Petroleum Company (NOGHCO)
(30.00%)
North October Petroleum Company
"NOPCO" (50.00%)
Ocwen Energy Pty Ltd (49.50%)
Oleoductos Canarios, S.A. (20.00%)
Optis, LLC (50.00%)a
Oslo Lufthaven Tankanlegg AS (33.33%)
PAE E & P Bolivia Limited (50.00%)
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
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
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
Block B, 2nd Floor, BP House, 10 Junction Avenue, Parktown, 2193, South Africa
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
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
85 El Nasr Road, Cairo, Cairo, Egypt
Level 3, 139 The Terrace, Wellington, 6011, New Zealand
Block B, 2nd Floor, BP House, 10 Junction Avenue, Parktown, 2193, South Africa
Avenida Atlântica, no. 1.130, 2nd floor (part), Copacabana, Rio de Janeiro, RJ, 22021-000, Brazil
Zum Ölhafen 207, 26384 Wilhelmshaven, Germany
4 Palestine Road, 4th District, New Maadi, Cairo, Egypt
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
6705 Steger Drive, Cincinnati OH 45237-3097, United States
Postboks 134, Gardermoen, NO-2061, Norway
Trinity Place Annex, Corner of Frederick & Shirley Streets, P.O. Box N-4805, Nassau, Bahamas
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
243
14. Related undertakings of the group – continued
PAE Oil & Gas Bolivia Ltda. (50.00%)
Pan American Energy Chile Limitada (50.00%)
Pan American Energy do Brasil Ltda. (50.00%)a
Pan American Energy Group, S.L. (50.00%)s
Pan American Energy Holdings Ltd. (50.00%)
Pan American Energy Iberica S.L. (50.00%)
Pan American Energy Investments Ltd. (50.00%)
Pan American Energy LLC (50.00%)a
Pan American Energy Uruguay S.A. (50.00%)
Pan American Fueguina S.A. (50.00%)
Pan American Sur S.A. (50.00%)
Paul Harling Mineralole GmbH & Co. KG (50.00%)g
Peninsular Aviation Services Company Limited
(25.00%)i
Pentland Aviation Fuelling Services Limited (50.00%)c
Petrostock SA (50.00%)
Pharaonic Petroleum Company "PhPC" (25.00%)
Prince William Sound Oil Spill Response Corporation
(25.00%)
Proteus Oil Pipeline Company, LLC (65.00%)a
PT Petro Storindo Energi (30.00%)
PT. Aneka Petroindo Raya (49.90%)
PT. Dirgantara Petroindo Raya (49.90%)
PTE Pipeline LLC (32.00%)a
Raffinerie de Strasbourg (33.33%)
Rahamat Petroleum Company (PETRORAHAMAT)
(50.00%)
Raimund Mineraloel GmbH (50.00%)
RAPI SA (62.51%)
Raststaette Glarnerland AG, Niederurnen (20.00%)
RD Petroleum Limited (49.00%)
Resolution Partners LLP (68.00%)g
Rhein-Main-Rohrleitungstransportgesellschaft mbH
(35.00%)
Rio Grande Pipeline Company (30.00%)g
RMF Holdings Limited (49.00%)
RocketRoute Limited (36.00%)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%)
SeaPort Midstream Partners, LLC (49.00%)a
Servicios Logísticos de Combustibles de Aviación,
S.L (50.00%)
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%)a
Shenzhen Dapeng LNG Marketing Company
Limited (30.00%)a
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%)a
Stansted Intoplane Company Limited (20.00%)
STDG Strassentransport Dispositions Gesellschaft
mbH (50.00%)
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
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
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, Jeddah 21442, Saudi Arabia
6th Floor (c/o Q8 Aviation), Dukes Court, Duke Street, Woking, GU21 5BH, United Kingdom
route de Pré-Bois 2, 1214, Vernier, Switzerland
70/72 Road 200, Maadi, Cairo, Egypt
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
AKR Tower 25th floor, Jalan Panjang No.5, Kebon Jeruk, Jakarta, 11530, Indonesia
Wisma AKR, 25th floor, Jalan Panjang No.5, Kebon Jeruk, , Jakarta Barat, 11530, Indonesia
2711 Centerville Road, Suite 400, Wilmington DE 19808, United States
24 Cours Michelet, 92800, Puteaux, France
70/72 Road 200, Maadi, Cairo, Egypt
Hörhof 1, 95473 Creußen, Germany
26 Kifissias Ave. and 2 Paradissou st., 15125 Maroussi, Athens, Greece
Nideracher 1, 8867, Niederurnen, Switzerland
Albert Alloo & Sons, 67 Princes Street, Dunedin, New Zealand
1675 Broadway, Denver CO 80202, United States
Godorfer Hauptstraße 186, 50997 Köln, Germany
Corporation Trust Center, 1209 Orange Street, Wilmington DE 19801, United States
KPMG, 247 Cameron Road, Tauranga, 3110, New Zealand
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, AB21 7PB, 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
Cogency Global Inc., 850 New Burton road, Suite 201, Dover, Delaware, 19904, Uunited States
Vía de los Poblados1, 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, SE1 7NA, United Kingdom
Fu Yong Town, Bao An county, ShenZhen Airport, Guangdong Province, China
Room 316 Excellence Mansion, No.98 Fuhua 1Rd, Futian District, Shenzhen, China
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
27 Route du Bassin Numéro 6, 92230, Gennevilliers, 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
Causeway House, 1 Dane Street, Bishop's Stortford, Hertfordshire, CM23 3BT, United Kingdom
Holstenhofweg 47, 22043 Hamburg, Germany
The parent company financial statements of BP p.l.c. on pages 219-245 do not form part of BP’s Annual Report on Form 20-F as filed with
the SEC.
244
BP Annual Report and Form 20-F 2017
14. Related undertakings of the group – continued
Box 7, 190 45 Arlanda, Sweden
Palm Grove House, P.O. Box 438, Road Town, Tortola, British Virgin Islands
c/o Husky Oil Operations Limited, 707 - 8th Avenue SW, Calgary AB T2P 1H5, Canada
Birmenstorferstrasse 2, 5507, Mellingen, Switzerland
Zwüscheteich, 8153, Rümlang, Switzerland
Auhafenstrasse 10a, 4132, Muttenz, Switzerland
Rijndwarsweg 3, 3198 LK Europoort, Rotterdam, Netherlands
Wesermünder Straße 1, 27729 Hambergen, Germany
Wesermünder Straße 1, 27729 Hambergen, Germany
Carretera de San Andréss/n, La Jurada-María Jiménez, Santa Cruz de Tenerife, Spain
Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
Sportallee 6, 22335 Hamburg, Germany
P.O. Box 309, Ugland House, 113 South Church Street, George Town, Grand Cayman, Cayman Islands
Shell Centre, London, SE1 7NA, United Kingdom
Shell Centre, London, SE1 7NA, United Kingdom
Town Hall, Lerwick, Shetland, ZE1 0HB, 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
Am Stadthafen 60, 45881 Gelsenkirchen, Germany
Brettenham House, 19 Lancaster Place, London, WC2E 7EN, United Kingdom
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
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
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
Kosmodamianskaya nab, 52/3, 115035, Moscow, Russian Federation
Stockholm Fuelling Services Aktiebolag (25.00%)
Stonewall Resources Ltd. (50.00%)
Sunrise Oil Sands Partnership (50.00%)g
Tankanlage AG Mellingen (33.33%)
TAR - Tankanlage Ruemlang AG (27.32%)
TAU Tanklager Auhafen AG (50.00%)
Team Terminal B.V. (22.80%)
Tecklenburg GmbH (50.00%)
Tecklenburg GmbH & Co. Energiebedarf KG
(50.00%)g
Terminales Canarios, S.L. (50.00%)
TFSS Turbo Fuel Services Sachsen GbR (20.00%)g
TGFH Tanklager-Gesellschaft Frankfurt-Hahn GbR
(50.00%)g
TGH Tankdienst-Gesellschaft Hamburg GbR
(33.33%)g
TGHL Tanklager-Gesellschaft Hannover-
Langenhagen GbR (50.00%)g
TGK Tanklagergesellschaft Koln-Bonn (25.00%)g
The Baku-Tbilisi-Ceyhan Pipeline Company (30.10%)z
The Consolidated Petroleum Company Limited
(50.00%)s
The Consolidated Petroleum Supply Company
Limited (50.00%)
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%)
TransTank GmbH (50.00%)
Tricoya Ventures UK Limited (35.56%)
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%)
Walton-Gatwick Pipeline Company Limited
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%)a
Yermak Neftegaz LLC (49.00%)a
a Member interest
b A shares
c A and B shares
d Ordinary, B shares, 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, A and B shares
m 0.008% 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 Subsidiary undertaking pursuant to sections 1162(2), 1162(3)(b) and Paragraph 6 of Schedule 7 of the Companies Act 2006
u 100% ordinary shares and 58.63% preference shares
v 92.31% B shares and 78.43% D shares
w Preference shares
x Unlimited redeemable shares
y 96.52% C shares
z 1.89% A shares and 40.80% B shares
The parent company financial statements of BP p.l.c. on pages 219-245 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 2017
245
THIS PAGE HAS BEEN LEFT BLANK INTENTIONALLY
Additional
disclosures
248 Selected financial information
251 Liquidity and capital resources
253 Upstream analysis by region
258 Downstream plant capacity
259 Oil and gas disclosures for the group
265 Environmental expenditure
265 Regulation of the group’s business
270 Legal proceedings
273
International trade sanctions
274 Material contracts
274 Property, plant and equipment
274 Related-party transactions
275 Corporate governance practices
275 Code of ethics
275 Controls and procedures
276 Principal accountants’ fees and services
276 Directors’ report information
277 Disclosures required under Listing Rule 9.8.4R
277 Cautionary statement
A
d
d
i
t
i
o
n
a
l
i
l
d
s
c
o
s
u
r
e
s
BP Annual Report and Form 20-F 2017
BP Annual Report and Form 20-F 2017
247
247
26_BP_AR_Financial_statements_contents_p115.indd 247
27/03/2018 10:39
Selected financial information
This information, insofar as it relates to 2017, has been extracted or derived from the audited consolidated financial statements of the BP group
presented on page 116. 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) adverse impact of non-operating items« and fair
value accounting effects«, before taxb
Taxation charge (credit) on non-operating items and fair value
accounting effects
Underlying RC profit«for the year
Earnings per sharec – 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
Capital expenditure«d
Organic capital expenditure«
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 datae
Basic weighted average number of shares
Diluted weighted average number of shares
2017
2016
2015
2014
2013
$ million except per share amounts
240,208
9,474
183,008
(430)
222,894
(7,918)
353,568
6,412
379,136
31,769
(2,294)
(3,712)
(79)
3,389
(853)
225
2,761
(1,865)
2,467
(57)
115
(1,597)
483
(999)
(1,653)
3,171
(82)
(6,482)
1,889
(569)
(5,162)
(1,462)
(947)
(223)
3,780
6,210
(1,917)
8,073
(1,548)
(6,463)
(307)
23,451
290
(60)
23,681
3,730
6,746
15,067
8,234
(9,244)
(325)
6,166
(3,162)
2,585
(4,000)
5,905
(4,171)
12,136
(1,009)
13,428
17.20
17.10
14.02
31.31
40.00
30.979
16,501
1,339
17,840
276,515
100,404
5,343
98,491
55,491
27.4%
0.61
0.60
(5.33)
13.79
40.00
29.418
16,675
777
17,452
263,316
96,843
5,284
95,286
51,666
26.8%
(35.39)
(35.39)
(28.18)
32.22
40.00
26.383
N/A
N/A
20,202
261,832
98,387
5,049
97,216
46,224
21.6%
20.55
20.42
43.90
66.00
39.00
23.850
N/A
N/A
23,192
284,305
112,642
5,023
111,441
45,977
16.7%
123.87
123.12
125.08
70.92
36.50
23.399
N/A
N/A
30,032
305,690
130,407
5,129
129,302
40,811
16.2%
Share million
19,693
19,816
18,745
18,855
18,324
18,324
18,385
18,497
18,931
19,046
a Profit attributable to BP shareholders.
b See pages 250 and 294 for further analysis of these items.
c A reconciliation to GAAP information is provided on page 294.
d From 2017 onwards we are reporting organic, inorganic and total capital expenditure on a cash basis which were previously reported on an accruals basis. This aligns with BP's financial
framework and is now consistent with other financial metrics used when comparing sources and uses of cash. An analysis of capital expenditure on a cash basis for 2015, 2014 and 2013 is
not available.
e The number of ordinary shares shown has been used to calculate the per share amounts.
248
«See Glossary
BP Annual Report and Form 20-F 2017
Additional information
Capital expenditure
Capital expenditure
Organic capital expenditure
Inorganic capital expenditurea
Organic capital expenditure by segment
Upstream
US
Non-US
Downstream
US
Non-US
Other businesses and corporate
US
Non-US
Organic capital expenditure by geographical area
US
Non-US
a 2017 includes amounts paid to acquire interests in Mauritania and Senegal and in the Zohr gas field in Egypt.
2017
2016
16,501
1,339
17,840
16,675
777
17,452
2017
2016
2,999
10,764
13,763
809
1,590
2,399
64
275
339
16,501
3,872
12,629
16,501
3,415
10,929
14,344
774
1,328
2,102
32
197
229
16,675
4,221
12,454
16,675
$ million
2015
N/A
N/A
20,202
$ million
2015
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
BP Annual Report and Form 20-F 2017
«See Glossary
249
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 b
Environmental and other provisions
Restructuring, integration and rationalization costsc
Fair value gain (loss) on embedded derivatives
Otherb d
Downstream
Impairment and gain (loss) on sale of businesses and fixed assetsa e
Environmental and other provisions
Restructuring, integration and rationalization costsc
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 costsc
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 costsc
Fair value gain (loss) on embedded derivatives
Gulf of Mexico oil spill responsef
Otherd
Total before interest and taxation
Finance costsf
Taxation credit (charge) on non-operating itemsg
Taxation - impact of US tax reformh
Total after taxation
2017
2016
(563)
1
(24)
33
(118)
(671)
579
(19)
(171)
—
—
389
—
—
—
—
—
—
(22)
(156)
(72)
—
(2,687)
90
(2,847)
(3,129)
(493)
1,172
(859)
(3,309)
2,391
(8)
(373)
32
(289)
1,753
405
(73)
(300)
—
(56)
(24)
62
—
—
—
(39)
23
—
(134)
(90)
—
(6,640)
(55)
(6,919)
(5,167)
(494)
2,833
—
(2,828)
$ million
2015
(1,204)
(24)
(410)
120
(717)
(2,235)
131
(108)
(607)
—
(6)
(590)
—
—
—
—
—
—
(170)
(151)
(71)
—
(11,709)
(155)
(12,256)
(15,081)
(247)
4,056
—
(11,272)
a See Financial statements – Note 3 for further information on impairments.
b 2016 includes a $319-million exploration write-back relating to Block KG D6 in India. In addition, an impairment reversal of $234 million was also recorded in relation to this block.
c Restructuring charges are classified as non-operating items where they relate to an announced major group restructuring. A major group restructuring is a restructuring programme affecting
more than one of the group’s operating segments that is expected to result in charges of more than $1 billion over a defined period. Following the Gulf of Mexico oil spill in 2010 and since
the fall in oil prices in late 2014, major group restructuring programmes were initiated. The current restructuring programme, aimed at simplifying and improving the efficiency of operations
across the group, commenced in the fourth quarter of 2014 and has resulted in cumulative non-operating charges of $2.6 billion to 31 December 2017, principally relating to redundancy
costs.
d 2017 includes BP’s share of an impairment reversal recognized by the Angola LNG equity-accounted entity, partially offset by other items. 2017 also includes the write-off of $145 million in
relation to the value ascribed to certain licences in the deepwater Gulf of Mexico as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. 2016 includes
the write-off of $334 million in relation to the value ascribed to the licence in Brazil as part of the accounting for the acquisition of upstream assets from Devon Energy in 2011. 2015
principally relates to BP’s share of impairment losses recognized by equity-accounted entities.
e 2017 primarily reflects the disposal of our shareholding in the SECCO joint venture.
f See Financial statements – Note 2 for further details regarding costs relating to the Gulf of Mexico oil spill.
g 2017 includes the tax effect of the increase in the provision in the fourth quarter for business economic loss and other claims associated with the Deepwater Horizon Court Supervised
Settlement Program (DHCSSP) at the new US tax rate.
h In 2017 the US tax reform reduced the US federal corporate income tax rate from 35% to 21%, effective from 1 January 2018. The impact disclosed has been calculated as the change in
deferred tax balances at 31 December 2017, excluding the increase in the provision in the fourth quarter for business economic loss and other claims associated with the DHCSSP, which
arises following the reduction in the tax rate. The impact of the US tax reform has been treated as a non-operating item because it is not considered to be part of underlying business
operations, has a material impact upon the reported result and is substantially impacted by Gulf of Mexico oil spill charges, which are also treated as non-operating items. Separate
disclosure is considered meaningful and relevant to investors.
250
«See Glossary
BP Annual Report and Form 20-F 2017
Liquidity and capital resources
Financial framework
BP’s financial framework sets a number of parameters in support of
growing shareholder value, distributions and returns, while
maintaining a strong balance sheet. BP’s objective over time is to
grow sustainable free cash flow« through a combination of operating
cash flow« growth and capital discipline, in service of growing
shareholder distributions over the long term.
Following the strong progress made in 2017 in rebalancing organic
sources and uses of cash flow«, we recommenced share buybacks
during the fourth quarter of 2017, with the intent to offset any ongoing
dilution from the scrip dividend programme over time. The shape of
the programme will not necessarily match the dilution on a quarterly
basis, but will reflect the ongoing judgement of factors including
changes in the environment, the underlying performance of the
business, the outlook for the group financial framework, and other
market factors which may vary quarter to quarter.
We expect operating cash flow excluding amounts relating to the Gulf
of Mexico oil spill to cover organic capital expenditure« of $15-16
billion and the full dividend« (including scrip) in 2018 at around $50
per barrel. Looking further out, this balancing point is expected to
steadily reduce to $35-40 per barrel by 2021, with organic capital
expenditure in a range of $15-17 billion, and not exceeding $17 billion
in any one year. In a constant price environment, surplus organic free
cash flow is expected to grow and be used to ensure the right
balance between deleveraging the balance sheet, growing
distributions and disciplined investment, depending on the context
and outlook at the time.
Gulf of Mexico oil spill payments are expected to be just over $3
billion in 2018, stepping down to around $2 billion in 2019 and around
$1 billion per annum thereafter, with divestment proceeds« of
around $2-3 billion per annum.
We continue to target a gearing« band of 20-30%, while maintaining
strong liquidity and debt market access.
Return on average capital employed« is targeted to improve from
5.8%a in 2017 to over 10% by 2021 (at $55 per barrel real), as we
continue to grow our underlying business.
a Nearest GAAP equivalent measures: Numerator – Profit attributable to BP shareholders
$3.4 billion; Denominator – Average capital employed $159.4 billion.
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 10 cents per share in 2017, the same as 2016.
The total dividend distributed to BP shareholders in 2017 was $7.9
billion (2016 $7.5 billion). Shareholders have the option to receive a
scrip dividend in place of receiving cash. In 2017 the total dividend
paid in cash was $6.2 billion (2016 $4.6 billion).
Details of share repurchases to satisfy the requirements of certain
employee share-based payment plans are set out on page 286. As
noted above, a share buyback programme to offset the dilutive
impact of the scrip dividend recommenced in the fourth quarter of
2017 with 51 million ordinary shares at a cost of $343 million,
including fees and stamp duty.
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 cash or
borrowings. Also see Risk factors on page 57 for further information
on risks associated with prices and markets and Financial
statements – Note 27.
The group’s gross debt at 31 December 2017 amounted to $63.2
billion (2016 $58.3 billion). Of the total gross debt, $7.7 billion is
classified as short term at the end of 2017 (2016 $6.6 billion). See
Financial statements – Note 24 for more information on the short-
term balance. Net debt« was $37.8 billion at the end of 2017, an
increase of $2.3 billion from the 2016 year-end position of $35.5
billion. The ratio of gross debt to gross debt plus equity at
31 December 2017 was 38.6% (2016 37.6%). The ratio of net debt to
net debt plus equity« was 27.4% at the end of 2017 (2016 26.8%).
See Financial statements – Note 25 for gross debt, which is the
nearest equivalent measure on an IFRS basis, and for further
information on net debt.
Cash and cash equivalents of $25.6 billion at 31 December 2017 (2016
$23.5 billion) are included in net debt. We manage our cash position
to ensure the group has adequate cover to respond to potential short-
term market illiquidity, and expect to maintain a robust cash position.
The group also has undrawn committed bank facilities of $7.6 billion
(see Financial statements – Note 27 for more information).
We believe that the group has sufficient working capital for
foreseeable requirements, taking into account the amounts of
undrawn borrowing facilities and levels of cash and cash equivalents,
and its ongoing ability to generate cash.
Standard & Poor’s Ratings’ long-term credit rating for BP is A- (stable
outlook) and the Moody’s Investors Service rating is A1 (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 23 and Note 27. Further information on the
management of liquidity risk and credit risk, and the maturity profile
and fixed/floating rate characteristics of the group’s debt are also
provided in Financial statements – Note 24 and Note 27.
Off-balance sheet arrangements
At 31 December 2017, the group’s share of third-party finance debt of
equity-accounted entities was $18.0 billion (2016 $14.6 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 2017 were $656 million (2016 $309 million) in
respect of liabilities of joint ventures«and associates«and $382
million (2016 $370 million) in respect of liabilities of other third parties.
Of these amounts, $645 million (2016 $298 million) of the joint
ventures and associates guarantees relate to borrowings and for
other third-party guarantees, $350 million (2016 $338 million) relate to
guarantees of borrowings. Details of operating lease commitments,
which are not recognized on the balance sheet, are shown in the
table below and provided in Financial statements – Note 26.
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 277 and Risk factors on page 57, 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.
BP Annual Report and Form 20-F 2017
«See Glossary
251
Contractual obligations
The following table summarizes the group’s capital expenditure commitments for property, plant and equipment at 31 December 2017 and the
proportion of that expenditure for which contracts have been placed.
Capital expenditure
Committed
of which is contracted
Total
28,295
11,340
2018
13,449
7,384
2019
7,120
2,562
2020
3,509
923
2021
1,480
178
2022
1,040
75
2023 and
thereafter
1,697
218
$ 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 2017, the group had committed to capital expenditure relating to investments in equity-accounted entities
amounting to $1,724 million. Contracts were in place for $1,451 million of this total.
The following table summarizes the group’s principal contractual obligations at 31 December 2017, distinguishing between those for which a
liability is recognized on the balance sheet and those for which no liability is recognized. Further information on borrowings is given in Financial
statements – Note 24 and more information on operating leases is given in Financial statements – Note 26.
$ million
Payments due by period
Expected payments by period under contractual obligations
Total
2018
2019
2020
2021
2022
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
Total
70,641
1,351
18,111
1,550
18,918
21,166
131,737
13,970
154,211
168,181
299,918
9,291
92
433
268
2,089
1,192
13,365
2,969
80,400
83,369
96,734
8,766
102
253
264
1,347
1,605
12,337
2,309
17,030
19,339
31,676
8,296
93
173
218
1,234
1,595
11,609
1,777
9,675
11,452
23,061
7,789
91
119
180
1,208
1,482
10,869
1,255
8,381
9,636
20,505
8,791
89
212
134
1,205
1,174
11,605
1,046
6,081
7,127
18,732
2023 and
thereafter
27,708
884
16,921
486
11,835
14,118
71,952
4,614
32,644
37,258
109,210
a Expected payments include interest totalling $8,269 million ($1,703 million in 2018, $1,485 million in 2019, $1,273 million in 2020, $1,070 million in 2021, $855 million in 2022 and $1,883
million thereafter).
b Expected payments include interest totalling $695 million ($54 million in 2018, $52 million in 2019, $48 million in 2020, $44 million in 2021, $39 million in 2022 and $458 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 2018 include purchase commitments existing at 31 December 2017
entered into principally to meet the group’s short-term manufacturing and marketing requirements. The price risk associated with these crude oil, natural gas and power contracts is
discussed in Financial statements – Note 27.
The following table summarizes the nature of the group’s unconditional purchase obligations.
Unconditional purchase obligations
Crude oil and oil products
Natural gas
Chemicals and other refinery feedstocks
Power
Utilities
Transportation
Use of facilities and services
Total
Total
76,884
27,685
5,548
4,464
539
20,426
18,665
154,211
2018
56,985
14,846
3,088
2,610
183
1,264
1,424
80,400
2019
7,114
4,734
1,819
965
117
947
1,334
17,030
2020
3,973
2,613
285
283
89
1,095
1,337
9,675
2021
3,746
1,938
82
151
37
1,314
1,113
8,381
$ million
Payments due by period
2022
1,945
1,622
77
99
23
1,277
1,038
6,081
2023 and
thereafter
3,121
1,932
197
356
90
14,529
12,419
32,644
252
«See Glossary
BP Annual Report and Form 20-F 2017
Upstream analysis by region
Our upstream operations are set out below by geographical area, with
associated significant events for 2017. 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 proved 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 Italy (in Rovigo), Spain (in
Bilbao), the UK (via the Isle of Grain) and the US (via Cove Point), with
the remainder marketed directly to customers. LNG is supplied to
customers in markets including Argentina, Chile, China, the
Dominican Republic, India, Israel, Japan, Kuwait, South Korea and
Taiwan.
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 in 2017 was generated from
three key areas: the Shetland area - comprising the Clair, Foinaven,
Magnus, and Schiehallion fields; the central area - comprising the
Andrew, Bruce, ETAP, Keith, Kinnoull and Rhum fields; and Norway,
through our equity accounted 30% interest in Aker BP established in
2016 (see below).
• In January 2017 we announced that we had agreed to sell 25% of
our 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. BP also agreed to transfer
operatorship of these assets to EnQuest. The sale price of
$85 million is expected to be met by EnQuest from future cash
flows from the assets, without any upfront payment to BP. The
transfer completed on 1 December. 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.
• We were awarded 25 blocks or part blocks in the UK’s 29th
Offshore Licensing Round in March 2017, representing the largest
acreage award for BP in the North Sea since the late 1990s. The
licence award includes three exploration wells.
• We announced in April that we had agreed to sell our Forties
Pipeline System (FPS) business (BP 100%) to INEOS for an upfront
cash consideration at the economic date of $125 million, adjusted
for net cash flows in the interim period, followed by contingent
payments between 2022 and 2024 of up to a further $125 million.
FPS is an integrated oil and NGLs transportation and processing
system that handles production from around 80 fields in the central
North Sea. As a result of this decision to sell, an impairment charge
of $387 million was recorded. The sale completed on 31 October.
BP’s existing transportation and processing rights in the system are
not affected by the divestment.
• Production from the redeveloped Schiehallion area started in May,
following completion of the multi-billion-dollar Quad 204 project,
designed to extend the life of the fields and unlock further
resources. The Schiehallion area comprises the Schiehallion (BP
33%) and Loyal (BP 50%) fields. The project included the
construction and installation of a floating, production, storage and
offloading (FPSO) vessel, a major upgrade and replacement of
subsea facilities and a continuous drilling programme of up to 20
new wells to enable full development of the associated reserves.
• We continued to progress development at the Maersk-operated
Culzean field (BP 32%) during the year. The installation of the gas
export pipeline and fixed jackets was completed in 2017, with
development drilling ongoing. First production is expected in 2019.
The field will be developed with three fixed platforms and a floating
storage unit.
• Aker BP announced an agreement to acquire Hess Norge AS in
October. On completion of the transaction in December, Aker BP
became the sole owner of the Valhall and Hod fields but
subsequently sold a 10% interest in each of these fields to Pandion
Energy AS. BP subscribed for additional new shares in Aker BP as
part of the financing of the acquisition of Hess Norge AS, and
remains an owner of 30% of the issued share capital in Aker BP.
• In November, we announced that we had agreed to sell a package
of our interests in the Bruce assets in the North Sea to Serica
Energy plc. We currently operate the assets, which comprise the
Bruce (BP 37%), Keith (BP 35%) and Rhum (BP 50%) fields, three
bridge-linked platforms and associated subsea infrastructure.
Under the terms of the agreement, Serica will pay BP an upfront
payment of £12.8 million (equivalent to $17.2 million), a share of
cash flows over the next four years, a consideration equivalent to
30% of our post-tax decommissioning costs and several contingent
payments dependent on future asset performance and product
prices. Overall, we expect to receive payments of around £300
million (equivalent to $403 million), the majority of which will be
received over the next four years. Subject to the receipt of
regulatory and other third-party approvals, we expect to complete
the sale and transfer of operatorship in the third quarter of 2018.
• The Clair field (BP 29% and operator) is the largest oilfield on the
UK Continental Shelf. Production began at the field, located 75
kilometres west of the Shetland Islands, in 2005. Its physical size
dictates development via a phased approach, with Clair Ridge as
the second phase of development. This has involved the
construction and installation of two new bridge-linked platforms,
the legs of which were installed in 2013. The final topside modules
were safely installed in 2016, completing the construction phase.
Commissioning offshore is well under way, with first oil expected
in late 2018.
• In September the US Office of Foreign Asset Control renewed BP’s
licence permitting certain US persons and US owned and
controlled companies to support Rhum activities in compliance
with US primary sanctions. The licence expires on 30 September
2018. The Rhum field is owned by BP (50%) and the Iranian Oil
Company (IOC, 50%) 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 273.
• During the year an exploration write-off of $178 million relating to
the Southern North Sea Carboniferous appraisal programme,
including the Ravenspurn North Deep well, was recognized. There
were two exploration discoveries in 2017, namely Achmelvich and
Capercaillie, both of which are currently being evaluated.
North America
Our upstream activities in North America are located in five areas:
deepwater Gulf of Mexico, the Lower 48 states, Alaska, Canada and
Mexico.
BP has around 260 lease blocks in the deepwater Gulf of Mexico, and
we operate four production hubs.
• We announced the start-up of the South Expansion major project at
our Thunder Horse platform in January 2017. Three producing wells
came online in 2017 and the final well followed in early 2018. 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 of four wells connected to the platform by two lines
installed on the seabed.
• During the year, a $68-million charge was recognized for the West
Capricorn rig while it was warm stacked awaiting transfer to other
projects. The rig returned to drilling operations in the fourth quarter
of 2017.
BP Annual Report and Form 20-F 2017
«See Glossary
253
• In December BP completed the disposal of 26.5% of its 27.5%
non-operated interest in the Perdido Regional Host to AL-Perdido
Holdings LLC. Perdido is a regional floating production hub for
three fields including Great White (BP 33%) in the Gulf of Mexico.
Alaska LNG LLC (BPAL) executed a co-operation agreement with
AGDC detailing BPAL's commitment to helping the state further
develop Alaska LNG. This agreement has been extended to 30
June 2018.
• In March 2017, we were awarded three leases in the OCS Central
Sale 247, in Mississippi Canyon Block 867 and Green Canyon
Blocks 738 and 870.
• We were also awarded three leases in the Gulf of Mexico Wide
Sale 249, in Green Canyon Block 451 and Mississippi Canyon
Blocks 820 and 864 in August.
• During the year exploration write-offs totalling $213 million were
recognised, the most significant being $148 million in connection
with the expiration of the Gila lease.
• See also Financial statements Note 1 for further information on
exploration leases.
The US Lower 48 onshore business has significant operated and non-
operated activities across Arkansas, Colorado, New Mexico,
Oklahoma, Texas and Wyoming producing natural gas, oil, NGLs and
condensate. It has a 1.4 billion boe proved reserve base as at
31 December 2017, predominantly in unconventional reservoirs (tight
gas«, shale gas and coalbed methane). This resource spans 3.1
million net developed acres and has approximately 9,400 operated
gross wells, with daily net production around 300mboe/d.
Since the beginning of 2015, our US Lower 48 onshore business has
operated as a separate business while remaining part of our
Upstream segment. It has its own governance, systems and
processes, and was established to increase competitive performance
through swift decision-making and innovation, while maintaining BP’s
commitment to safe, reliable and compliant operations.
• In East Texas the Haynesville and Bossier development is
underway. This material development increased BP’s net natural
gas production for the fourth quarter of 2017 in the East Business
Unit by around 50% compared to the previous year.
• In August, we announced that a natural gas well in the Mancos
Shale, New Mexico (BP 100%) had been brought on line. We
believe the field has the potential to be a significant new source of
US gas supply.
• In the fourth quarter an impairment charge of $321 million was
recognized as a result of changes in reserves estimates.
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 the year.
Our focus continues to be on safe and reliable operations, renewing
Prudhoe Bay infrastructure and minimizing oil production decline. For
the past three years BP has successfully combated decline at
Prudhoe Bay through wellwork and improved operating field
efficiencies, with production being largely maintained. Infrastructure
renewal activities in 2017 included compressor replacements, fire and
gas system upgrades, safety system upgrades, pipeline renewal,
facility piping upgrades and facility-siting projects. BP also owns
significant interests in eight producing fields operated by others, as
well as a non-operating interest in the Liberty prospect.
• 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 3 billion cubic feet per day (bcf/d) (up to 20
million tonnes per annum) supplied from the Prudhoe Bay and
Point Thomson fields. In April, the Alaska Gasline Development
Corporation (AGDC), a state entity which has led the project since
December 2016, submitted a formal application for an authorization
to site, construct, and operate an integrated LNG project. AGDC
also conducted extensive marketing activities in Asia in 2017
including signing a memorandum of understanding with the Korea
Gas Corporation (KOGAS), signing a joint development agreement
with China Petroleum and Chemical Corporation (Sinopec), Bank of
China, and the Chinese Investment Corporation, signing a
memorandum of understanding with PetroVietnam and signing a
Letter of Intent with Tokyo Gas Company. In January 2017 BP
• The Prudhoe Bay oil field (BP 26% and operator) on Alaska’s North
Slope reached 40 years of production in 2017, a milestone that
highlights its important contribution to US energy security and the
economy of the state. Since the field began production in 1977, it
has recovered more than 12.5 billion barrels of oil. The original
estimated recovery for Prudhoe Bay was 9.6 billion barrels, with an
additional 3 billion barrels so far unlocked through innovations in
oilfield technology. Prudhoe Bay remains the third largest oil field in
the US on a proved reserves basis.
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 Unocal (1.37%) gave notice to the other
TAPS owners of their intention to withdraw as an owner of TAPS. The
remaining owners and Unocal have not yet reached agreement
regarding the terms for the transfer of Unocal’s interest in TAPS.
• In 2017, the parties involved in TAPS tariff matters at the Federal
Energy Regulatory Commission (FERC) and the Regulatory
Commission of Alaska (RCA) reached an agreement to settle all
challenges pending before FERC involving TAPS interstate rates for
the years 2009-2015 and establish a mechanism for calculating
interstate rate ceilings for TAPS for the period from 2016 through
2021, as well as subsequent years unless otherwise terminated.
The agreement resolves all challenges pending before the RCA
involving TAPS intrastate rates from 2008 to the present, and
establish intrastate rate ceilings for the future through 30 June
2019. RCA approval was granted in January 2018 and FERC
approval in February 2018. Once all appeal periods have run, if the
agreements are approved, the parties will proceed with
implementing the settlement agreements, including issuing tariff
refunds. Implementation will result in production tax and royalty
payments to the State of Alaska while releasing some previously
accrued liability provisions within BP Alaska.
In Canada, BP is focused on oil sands development as well as
pursuing offshore exploration opportunities. We utilize in-situ steam-
assisted gravity drainage (SAGD) technology in our oil sands
developments, 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 lease areas
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 Nova Scotia, Newfoundland and
Labrador and the Canadian Beaufort Sea.
In Mexico, we have interests in two exploration joint ventures« in the
Saline Basin with Statoil and Total, Block 1 (BP 33% and operator) and
Block 3 (BP 33%). Both properties have submitted an exploration plan
to Comisión Nacional de Hidrocarburos (CNH), the Mexican regulator,
and approval was received in March 2018.
South America
BP has upstream activities in Brazil and Trinidad & Tobago, and
through Pan American Energy Group (PAEG), in Argentina and Bolivia.
In Brazil BP has interests in 21 exploration concessions across five
basins.
• In October, we won two licences in the third Pre-Salt Bid Round in
Brazil, the Alto De Cabo Frio Central block (BP 50%), and the
Peroba block (BP 40%).
• In the North Campos basin, we continue work on the BM-C-32
(Itaipu) and BM-C-30 (Wahoo) projects with the potential for a joint
development or tie back between them. A decision to move into
front-end engineering for a potential long-term test is planned for
November 2018.
• Following the licence extension to 2019 which was approved in
2016, seismic processing and prospect inventory development
progressed in 2017 in Block BAR-M-346 in the Barreirinhas basin.
254
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BP Annual Report and Form 20-F 2017
• BP continues to progress the preparatory activities for drilling
exploration wells in the Foz do Amazonas Basin, with a BP-
operated well scheduled to spud in 2020. An extension request
was submitted to the Brazilian National Petroleum Agency (ANP)
regarding BP-operated block FZA-M-59. We also expect drilling
activity to commence in 2019 on our other non-operated interests
in Foz de Amazonas (BP 30%).
• In the South Campos basin, following approval of the revised
appraisal plan by ANP in 2016, in Block BM-C-35 we have
postponed the decision to move into Appraisal Plan Stage II and
commit to an additional pre-salt well or relinquish the area, until
October 2018.
In Argentina and Bolivia BP conducts activity through PAEG, which
also has activities in Mexico.
• In December, we confirmed that the formation of Pan American
Energy Group (PAEG) had completed. The new company, owned by
BP (50%) and Bridas Corporation (50%), is now the largest
privately owned integrated energy company operating in Argentina.
PAEG was formed in a cash free transaction by the combination of
Pan American Energy and Axion Energy (Axion). Pan American
Energy had been owned 60:40 by BP and Bridas Corporation and
Axion had been wholly-owned by Bridas Corporation.
In Trinidad & Tobago BP holds exploration and production licences and
production-sharing agreements«(PSAs) covering 1.8 million acres
offshore of the east and north-east coast. Facilities include 14
offshore platforms and two onshore processing facilities. Production
comprises gas and associated liquids.
BP also has a shareholding in the Atlantic LNG liquefaction plant, BP’s
shareholding averages 39% across four LNG trains« with a
combined capacity of 15 million tonnes per annum. We sell 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. We
market the remaining equity LNG entitlement from trains 2, 3 and 4
to the US, UK, Spain and South America.
• The Trinidad onshore compression project (BP 70%) started up in
April. The facility is expected to improve production capacity by
increasing production from low-pressure wells in BP’s existing
acreage in the Columbus Basin using an additional inlet
compressor at the Point Fortin Atlantic LNG plant.
• We announced the Savannah and Macadamia gas discoveries in
June (both BP 70%). The Savannah exploration well was drilled east
of the Juniper field into an untested fault block using a semi-
submersible rig, and penetrated two hydrocarbon-bearing
reservoirs. Based on the success of this well BP expects to develop
these reservoirs through future tie-backs to the Juniper platform.
The Macadamia well was drilled to test exploration and appraisal
segments below the existing SEQB discovery south of the
producing Cashima field. This discovery is expected to support a
new platform in the future.
• Also in June, we announced that development of the Angelin
offshore gas project had been sanctioned. The project will involve
construction of a new platform, BP’s 15th offshore production
facility, 60 kilometres off the south-east coast of Trinidad in water
depths of approximately 65 metres. The development will include
four wells, with gas from Angelin flowing to the Cassia B hub for
processing via a new pipeline to the Serrette platform. Drilling is
expected to start in late 2018 with first gas expected in 2019.
• In August, we announced the start of production from our Juniper
project. Juniper is BP’s first subsea development in Trinidad and is
expected to boost our gas production capacity by around 590
mmscf per day. The development produces gas from the Corallita
and Lantana fields via the new Juniper platform, 80 kilometres off
the south-east coast of Trinidad.
Africa
BP’s upstream activities in Africa are located in Algeria, Angola, Côte
d'Ivoire, Egypt, Libya, and 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 production-sharing contract (PSC) expired in
September 2014 and our exit concluded in 2017.
• In December, BP and Statoil signed an extension agreement for
the In Amenas PSC with Sonatrach, the Algerian state-owned
energy company. The agreement has been submitted to the
Algerian authorities for ratification.
In Angola, BP owns an interest in six major deepwater offshore
licences and is operator in two of these, blocks 18 and 31, that are
producing. We also have an equity interest in the Angola LNG plant
(BP 13.6%).
• In June, we announced that as part of our ongoing portfolio
evaluation we would relinquish our 50% interest in block 24/11
offshore. The Katambi gas discovery made in 2014 has not been
determined to be commercial. As a result of this, and other
exploration write-offs, a total of $729 million was recognized during
the year.
In December, BP and Kosmos Energy (KE) announced that they had
been awarded five new offshore oil blocks in Côte d’Ivoire, under
agreements with the government of Côte d'Ivoire and the state oil
company Société Nationale d'Operations Pétrolières de la Côte
d'Ivoire (PETROCI) (BP 45%, KE 45%, PETROCI 10%).
In Egypt, BP and its partners currently produce 10% of Egypt’s
liquids« production and almost 40% of its gas production.
• We announced the Qattameya discovery in March 2017, the third
gas discovery in the North Damietta offshore concession in the
East Nile Delta. Options to tie the discovery back to nearby
infrastructure are being studied.
• In 2017 exploration write-offs of $368 million were recognized for a
number of wells including GEB East, Mocha and Tarif Deep, as a
result of unsuccessful exploration drilling and the relinquishment of
exploration blocks.
• BP announced the start-up of gas production from the Taurus and
Libra fields in the West Nile Delta development (BP 82.75%) in
May. This development comprises five fields across the North
Alexandria and West Mediterranean Deepwater offshore blocks
and is being developed as three separate projects to enable BP and
its partners to accelerate gas production commitments to Egypt.
All projects are expected to be onstream by 2019. Development of
the Taurus and Libra fields were fast-tracked following approval in
2015. It is a subsea greenfield development including nine wells
and 42 kilometre tieback to existing onshore processing facilities.
• Also in May, development of the Baltim South West field was
sanctioned. A dedicated mobile offshore production unit will be
installed and tied back to existing infrastructure through a new
offshore/onshore pipeline.
• In February 2018, we announced the start-up of the Atoll field in
the North Damietta concession following the drilling of three
deepwater wells 950 metres below the water’s surface. Early
production first started in December before the field came fully on
line in January.
• In December, the first phase of well drilling operations at the Zohr
gas field concluded and production has commenced. Production
had reached 350 million cubic feet per day at year end. BP did not
exercise the option to purchase an additional 5% interest in the
field by the end of 2017. The final purchase consideration on the
Zohr acquisition was $564 million. During 2017 Rosneft completed
the acquisition of a 30% stake in a concession agreement to
develop the Zohr field.
In Libya, BP partners 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%).
The EPSA continues to be in force majeure. BP wrote off all balances
associated with the Libya EPSA in 2015.
In Mauritania and Senegal, BP has partnered with Kosmos Energy
and has a 62% participating interest in the C-6, C-8, C-12 and C-13
BP Annual Report and Form 20-F 2017
«See Glossary
255
exploration blocks in Mauritania and a 60% participating interest in
the Cayar Profond and St Louis Profond exploration blocks in Senegal.
Together these blocks cover approximately 33,000km2. 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.
• Under the terms of the agreements with Kosmos Energy,
announced in December 2016, BP paid Kosmos cash bonuses of
$162 million on completion. BP will carry exploration and appraisal
costs of $228 million for Kosmos along with its development costs
of $533 million, which include front-end engineering and design
studies. Kosmos will also receive a contingent bonus of up to $2
per barrel for up to 1 billion barrels of liquids, as a production
royalty, subject to a future liquids discovery and oil price. The
Mauritania deal with Kosmos completed in December 2016 and the
Senegal deal completed in February 2017.
• BP and Kosmos Energy announced the Yakaar-1 gas discovery
offshore Senegal in the Cayar Offshore Profond block in May. This
followed the earlier exploration success that led to the Tortue
discovery, where we completed a drill stem test in 2017.
• In July, we completed a deal with Timis Corporation to acquire their
30% interest in the Cayar Profond and the St Loius Profond blocks,
deepening our interest in these Senegal blocks.
• We completed the acquisition of a 15% participating interest in the
C-18 exploration block in Mauritania from Tullow in September. This
block is now operated by Total.
• In October, Kosmos Energy announced that the Hippocampe-1
exploration well, in the C-8 block was unsuccessful. As a result, an
exploration write-off of $69 million was recognized.
• In December, Kosmos Energy announced that the Lamantin-1
exploration well in block C-12 was unsuccessful. As a result, an
exploration write-off of $45 million was recognized.
• In February 2018, Kosmos Energy announced that the Requin
Tigre-1 well in the Saint Louis Profond block, offshore Senegal, was
fully tested but did not encounter hydrocarbons.
• In February 2018, the governments of Mauritania and Senegal
signed an Inter-Government Cooperation Agreement (ICA) which
will enable the development of the BP-operated Tortue/Ahmeyim
gas project to continue to move towards a final investment
decision. The ICA provides for development of the Tortue/Ahmeyim
gas field through cross-border unitisation, with a 50%-50% initial
split of resources and revenues and a mechanism for future equity
redeterminations based on actual production and other technical
data. The Tortue/Ahmeyim gas field is located offshore on the
border between Mauritania and Senegal. BP has completed
significant engineering design towards the project, an integrated
gas value chain and near-shore liquefied natural gas (LNG)
development which would export LNG to global markets as well as
supplying gas to Senegal and Mauritania.
In Morocco, BP exited its final licence, the Essaouira offshore licence
(BP 45%) in 2017. The majority of balances associated with the licence
were written off in 2016, with the exception of a small payment for
unfulfilled exploration commitments which was made in 2017.
Asia
BP has activities in Abu Dhabi, Azerbaijan, China, India, Iraq, Kuwait,
Oman and Russia.
In China we have a 30% equity stake in the Guangdong LNG
regasification terminal and trunkline project with a total storage
capacity of 640,000m3. The project is supplied under a long-term
contract with Australia’s North West Shelf venture (BP 16.67%).
Dazu block, and drilling activity continued to progress in the two
blocks in the Sichuan basin.
In Azerbaijan, BP operates two PSAs, Azeri-Chirag-Gunashli (ACG) (BP
30.37%) 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 273.
• The Shah Deniz Stage 2 project and associated South Caucasus
Pipeline expansion project are now substantially complete in terms
of engineering, procurement, construction and commissioning, and
remain on target for first gas delivery in 2018. We achieved a
number of major project milestones in 2017, including the
installation of both processing and utilities platforms offshore,
installation of all processing facilities at the onshore terminal and
completion of pipeline construction in Azerbaijan and Georgia.
• In September, the joint development and PSA for the ACG fields
was extended with the signing of an amended and restated PSA
between the State Oil Company of the Republic of Azerbaijan
(SOCAR) and the contractor parties. The renewed PSA has been
ratified by the Azerbaijani parliament and was effective from 1
January 2018. It extends the PSA’s term by 25 years to 2049 and
includes an improved contractor parties’ profit share at a fixed rate
of 25%. Under the terms of the agreement, BP’s interest changes
from 35.78% to 30.37% from the agreement’s effective date, with
a bonus of $1.46 billion (BP net), payable to the government of
Azerbaijan in equal instalments over eight years. Following signing
of the PSA extension, BP and its partners approved the next stage
of development of the Azeri-Central East project to examine the
potential for a further production platform to be located between
the existing Central Azeri and East Azeri platforms. A final
investment decision on this project is anticipated in 2019.
BP holds a 30.1% interest in and operates the Baku-Tbilisi-Ceyhan
(BTC) oil pipeline. The 1,768-kilometre pipeline transports oil from the
BP-operated ACG oilfield and gas condensate from the Shah Deniz
gas field in the Caspian Sea, along with other third-party oil, to the
eastern Mediterranean port of Ceyhan. The pipeline has a capacity of
1mmboe/d with an average throughput in 2017 of 694mboe/d.
BP is technical operator of, and currently holds a 28.83% interest in,
the 693 kilometre 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 2017 of
125mboe/d. BP (as operator of Azerbaijan International Operating
Company) also operates the Western Route Export Pipeline that
transports ACG oil to Supsa on the Black Sea coast of Georgia, with
an average throughput of 77mboe/d in 2017.
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.
In Oman, BP operates the Khazzan field in block 61 (BP 60%).
• In September, we announced the start of production from the
Khazzan gas field ahead of schedule and under budget. Khazzan is
located in block 61 which is operated by BP in partnership with
Oman Oil Company Exploration and Production. Phase one of the
Khazzan development is made up of 200 wells feeding into a two-
train central processing facility. Production from this phase at year
end had reached 0.3 billion cubic feet of gas per day (BP net).
• BP has two PSCs for shale gas exploration, development and
• In 2016 BP signed an agreement to extend block 61 and unlock
production in the Neijiang-Dazu block and Rong Chang Bei block in
the Sichuan basin, China. The two blocks, both in the exploration
phase, cover a total area of approximately 2,500km2. China
National Petroleum Corporation (CNPC) is the operator. In 2017, the
seismic acquisition programme was completed in the Neijiang–
Phase two of the Khazzan development, known as Ghazeer. This is
expected to add a further 0.5 billion cubic feet of gas per day, and
the final investment decision is expected in early 2018.
In Abu Dhabi, BP holds an equity interest of 14.67% in the ADNOC
Offshore concession (formerly ADMA) and a 10% interest in the
ADNOC Onshore concession (formerly ADCO). We also have a 10%
256
«See Glossary
BP Annual Report and Form 20-F 2017
• Following the decision taken in March 2016 not to progress with
the floating LNG development, the Browse joint venture
participants continue to evaluate a range of alternative
development options, and are expecting to select one in 2018.
• We announced that production had commenced from the
Persephone project on the North West Shelf (BP 16.67%) in
August. The development comprises two subsea wells tied back to
the existing North Rankin complex.
• Following the cancellation of the Great Australian Bight project, the
Ocean Great White rig is currently warm stacked. A number of
options for its deployment or renegotiation of the contractual terms
remain under review and are being worked actively with the rig
operator.
In Papua Barat, Eastern Indonesia, BP operates the Tangguh LNG
plant (BP 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, and Japan through a combination of long, medium and
short-term contracts.
• The Tangguh expansion project, which was approved for final
investment decision in 2016, is progressing on schedule. The
project includes a third LNG processing train (train 3), adding 3.8
million tonnes per annum (mtpa) of production capacity to the
existing facility, bringing total plant capacity to 11.4mtpa. The
project also includes two offshore platforms, 13 new production
wells, an expanded LNG loading facility, and supporting
infrastructure. This will enable BP to continue playing 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.
• Approval from the government of Indonesia to relinquish BP’s 32%
interest in the Chevron-operated West Papua III was received in
November. Approval for the relinquishment of West Papua I (also
BP 32%) has not yet been obtained.
equity shareholding in ADNOC LNG (formerly ADGAS) that supplied
approximately 5.6 million tonnes of LNG (263.6bcfe regasified) in
2017.
Our interest in the ADNOC Offshore concession expired in March
2018. Current production is approximately 670mb/d gross, with
partners lifting according to equity participation. The concession,
together with all related rights and obligations, has reverted back to
the government of the Emirate of Abu Dhabi. Our interest in the
ADNOC Onshore concession expires at the end of 2054.
In 2016 BP signed an enhanced technical service agreement for south
and east Kuwait conventional oilfields, which includes the Burgan
field, with Kuwait Oil Company. Implementation of the agreed
2017-2018 plan for the Burgan oil field is underway as planned.
In India, we have a 30% participating interest in two oil and gas PSAs
and a 33.33% participating interest in one oil and gas PSA, all
operated by Reliance Industries Limited (RIL). We also have a stake
with RIL in a 50:50 joint venture (India Gas Solutions Private Limited)
for the sourcing and marketing of gas in India.
• In 2017 BP recorded a $30-million impairment reversal and a $56-
million reversal of exploration write-offs due to increased
confidence in the progress of the projects in Block KG D6. This fully
reverses all previously booked impairments on the block.
• In June, BP and its partners announced that they had taken an
investment decision to progress development of the R-Series
deepwater gas fields in Block KG D6 off the east coast of India. The
R-Series fields will be developed as a subsea tieback to existing
infrastructure in the block. The project is expected to come
onstream in 2020 and is the first of three planned projects in Block
KG D6 to be developed in an integrated manner. In October, field
development plans for the Satellite Cluster and D55 developments
were submitted for requisite approvals under the PSA.
In Iraq, BP holds a 47.6% working interest and is the lead contractor
in the Rumaila technical service contract in southern Iraq. The
technical services contract runs to December 2034. Rumaila is one of
the world’s largest oil fields, comprising five producing reservoirs. Our
operations are not impacted by the continued instability and sectarian
violence in the north and west of the country. Production as at year
end 2017 was 61 mboe/d (BP net).
• In January 2018, BP signed a Letter of Intent to support Iraq's
North Oil Company with current operations and development plans
for longer-term redevelopment of the Kirkuk field. This is an
extension of a Letter of Intent signed in 2013.
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 38 for
further details). We also hold a 49% interest in Yermak Neftegaz LLC,
another joint venture with Rosneft to conduct exploration in the West
Siberian and Yenisei-Khatanga basins. Yermak Neftegaz LLC currently
holds seven exploration and production licences. The venture is also
carrying 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 largest single source 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.
BP Annual Report and Form 20-F 2017
«See Glossary
257
Downstream plant capacity
The following table summarizes BP group’s interests in refineries and average daily crude distillation capacities as at 31 December 2017.
Fuels value chain
US
US North West
US East of Rockies
Europe
Rhine
Iberia
Rest of world
Australia
New Zealand
Southern Africa
Country
Refinery
US
Cherry Point
Whiting
Toledo
Germany
Netherlands
Spain
Bayernoilc
Gelsenkirchen
Lingen
Rotterdam
Castellón
Australia
New Zealand
South Africa
Kwinana
Whangareic d
Durbanc
Total BP share of capacity at 31 December 2017
a Crude distillation capacity is gross rated capacity, which is defined as the highest average sustained unit rate for a consecutive 30-day period.
b BP share of equity, which is not necessarily the same as BP share of processing entitlements.
c Indicates refineries not operated by BP.
d 33mb/d reflects BP share of processing entitlement, which is not the same as BP share of equity.
Petrochemicals production capacitya
The following table summarizes BP group’s share of petrochemicals production capacities as at 31 December 2017.
Crude distillation capacitiesa
Group interestb
(%)
BP share
thousand barrels
per day
100
100
50
10
100
100
100
100
100
10.1
50
236
430
80
746
22
265
97
377
110
871
152
33
90
275
1,892
BP share of capacity
thousand tonnes per annumb
Geographical area
US
Europe
UK
Belgium
Germany
Rest of world
Trinidad & Tobago
China
Indonesia
South Korea
Malaysia
Taiwan
Site
Group interestc
(%)
Cooper River
Texas Cityd
Hull
Geel
Gelsenkirchene
Mülheime
Point Lisas
Chongqing
Nanjing
Zhuhaif
Merak
Ulsang
Kertih
Mai Liao
Taichung
100
100
100
100
100
100
36.9
51
50
85
100
34 to 51
70
50
61.4
Total BP share of capacity at 31 December 2017
PTA
1,400
—
1,400
—
1,400
—
—
1,400
—
—
—
2,500
500
—
—
—
500
3,500
6,300
PX
—
900
900
—
700
—
—
700
—
—
—
—
—
—
—
—
—
—
1,600
Acetic
acid
Olefins and
derivatives
—
600
600
500
—
—
—
500
—
200
300
—
—
300
400
200
—
1,400
2,500
—
—
—
—
—
3,300
—
3,300
—
—
—
—
—
—
—
—
—
—
3,300
Product
Others
—
100
100
200
—
—
200
400
700
100
—
—
—
100
—
—
—
900
1,400
15,100
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 For acetic acid, group interest is quoted at 100%, reflecting the capacity entitlement which is marketed by BP.
e 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.
f BP Zhuhai Chemical Company Ltd is a subsidiary«of BP, the capacity of which is shown above at 100%.
g Group interest varies by product.
258
«See Glossary
BP Annual Report and Form 20-F 2017
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 2017 BP had material volumes of proved undeveloped
reserves held for more than five years in Russia, 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 2016 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 2017 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 2017 we progressed 1,671mmboe of proved undeveloped reserves
(1,119mmboe 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
$15,277 million in 2017 ($10,695 million for subsidiaries and $4,582
million for equity-accounted entities). The major areas with
progressed volumes in 2017 were Argentina, Trinidad, Russia, the UK
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 material revisions to our proved undeveloped resources in
the UAE as a result of development expansion, Azerbaijan as a result
of the extension of the production license and in Russia as a result of
new gas contracts and development drilling results. 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
Proved undeveloped reserves at 1 January 2017
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
2017
volumes in mmboea
7,797
842
236
769
122
(65)
1,904
31
(1,671)
8,060
Subsidiaries only
Proved undeveloped reserves at 1 January 2017
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
2017
volumes in mmboea
4,068
402
203
413
57
(2)
1,073
31
(1,119)
4,052
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:
BP Annual Report and Form 20-F 2017
«See Glossary
259
• well data used to assess the local characteristics and conditions of
reservoirs and fluids
• 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 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 by the group’s petroleum engineers or by independent
petroleum engineering consulting firms and then 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 2017, 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 2017. 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
88% of our total proved reserves of subsidiaries at
31 December 2017 were held through joint operations«(86% in
2016), and 34% of the proved reserves were held through such joint
operations where we were not the operator (31% in 2016).
Estimated net proved reserves of crude oil at
31 December 2017a b c
UK
Rest of Europe
USd
Rest of North Americae
South Americaf
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entities
Total
Developed
Undeveloped
245
—
932
54
10
281
1,040
31
2,592
3,473
6,064
164
—
492
195
6
28
642
11
1,537
2,603
4,140
million barrels
Total
409
—
1,423
248
16
309
1,682
42
4,129
6,076
10,205
260
«See Glossary
BP Annual Report and Form 20-F 2017
Proved reserves replacement
Total hydrocarbon proved reserves at 31 December 2017, on an oil
equivalent basis including equity-accounted entities, increased by 4%
(increase of 4% for subsidiaries and increase of 3% for equity-
accounted entities) compared with 31 December 2016. Natural gas
represented about 42% (53% for subsidiaries and 30% for equity-
accounted entities) of these reserves. The change includes a net
increase from acquisitions and disposals of 47mmboe (increase of
90mmboe within our subsidiaries and decrease of 43mmboe within
our equity-accounted entities). Acquisition activity in our subsidiaries
occurred in Egypt, the US and the UK, and divestment activity in our
subsidiaries in the UK. In our equity-accounted entities acquisitions
occurred in our Aker BP and Rosneft equity-accounted entities and
divestments occurred in our Aker BP and in our Pan American Energy
(PAE) equity-accounted entities.
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 2017, the proved reserves replacement ratio
excluding acquisitions and disposals was 143% (109% in 2016 and
61% in 2015) for subsidiaries and equity-accounted entities, 133% for
subsidiaries alone and 159% for equity-accounted entities alone.
There were material increases (264mmboe) of reserves due to
extension of the date of cessation of production across the group due
to higher oil and gas prices, but these were partially offset by
decreases (150mmboe) in PSAs, principally in Azerbaijan, Indonesia
and Iraq resulting from decreased cost recovery volumes due to
higher oil and gas prices.
In 2017 net additions to the group’s proved reserves (excluding
production and sales and purchases of reserves-in-place) amounted
to 1,926mmboe (1,084mmboe for subsidiaries and 842mmboe for
equity-accounted entities), through revisions to previous estimates,
improved recovery from, and extensions to, existing fields and
discoveries of new fields. The subsidiary additions through improved
recovery from, and extensions to, existing fields and discoveries of
new fields were in existing developments where they represented a
mixture of proved developed and proved undeveloped reserves.
Volumes added in 2017 principally resulted from the application of
conventional technologies and extensions of the cessation of
production as a result of higher prices. The principal proved reserves
additions in our subsidiaries were in UAE, Oman, Azerbaijan and the
US. We had material reductions in our proved reserves in Iraq
principally due to higher oil and gas prices. The principal reserves
additions in our equity-accounted entities were in PAE and Rosneft.
17% of our proved reserves are associated with PSAs. The countries
in which we operated under PSAs in 2017 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 198.
Estimated net proved reserves of natural gas liquids at
31 December 2017a 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
11
—
177
—
2
21
—
5
216
97
313
3
—
69
—
28
—
—
1
102
53
154
Total
14
—
246
—
30
21
—
6
318
149
467
Estimated net proved reserves of liquids«
Subsidiariesf
Equity-accounted entitiesg
Total
Developed
Undeveloped
2,808
3,569
6,377
1,639
2,656
4,295
million barrels
Total
4,447
6,225
10,672
Estimated net proved reserves of natural gas at
31 December 2017a b
UK
Rest of Europe
US
Rest of North America
South Americah
Africa
Rest of Asia
Australasia
Subsidiaries
Equity-accounted entitiesi
Total
Developed Undeveloped
Total
billion cubic feet
523
—
5,238
(1)
2,862
1,159
2,755
2,730
15,266
7,955
23,221
320
—
3,086
—
3,330
1,510
4,245
1,505
13,997
7,841
21,838
843
—
8,323
(1)
6,193
2,670
7,000
4,235
29,263
15,796
45,060
Estimated net proved reserves on an oil equivalent basis
Subsidiaries
Equity-accounted entities
Total
million barrels of oil equivalent
Developed
Undeveloped
5,440
4,941
10,381
4,052
4,008
8,060
Total
9,492
8,949
18,441
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 2017 marker prices used were Brent« $54.36/bbl (2016 $42.82/bbl and 2015 $54.17/
bbl) and Henry Hub« $2.96/mmBtu (2016 $2.46/mmBtu and 2015 $2.59/mmBtu).
c Includes condensate.
d 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.
e All of the reserves in Canada are bitumen.
f Includes 14 million barrels of liquids in respect of the 30% non-controlling interest in BP
Trinidad and Tobago LLC.
g Includes 338 million barrels of liquids in respect of the non-controlling interest in Rosneft
held assets in Russia including 32 million barrels held through BP’s equity-accounted
interest in Taas-Yuryakh Neftegazodobycha.
h Includes 1,860 billion cubic feet of natural gas in respect of the 30% non-controlling
interest in BP Trinidad and Tobago LLC.
i
Includes 306 billion cubic feet of natural gas in respect of the non-controlling interest in
Rosneft held assets in Russia including 12 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.
BP Annual Report and Form 20-F 2017
«See Glossary
261
BP’s net production by country – crude oila and natural gas liquids
2017
2016
Crude oil
2015
thousand barrels per day
BP net share of productionb
Natural gas
liquids
2017
2016
2015
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
Abu Dhabic
Azerbaijan
Western Indonesiac
Iraq
India
Oman
Total Rest of Asia
Total Asia
Australiac
Eastern Indonesiac
Total Australasia
Total subsidiaries
Equity-accounted entities (BP share)
Rosneft (Russia, Canada, Venezuela, Vietnam)
Abu Dhabif
Argentinac
Boliviac
Egypt
Norwayc
Russiac
Angola
Other
Total equity-accounted entities
Total subsidiaries and equity-accounted entitiesg
80
—
—
80
109
10
251
370
20
20
390
12
12
192
40
9
241
158
90
—
73
1
2
325
325
15
1
17
1,064
900
99
60
3
—
31
5
1
—
1,099
2,163
79
24
24
102
107
12
216
335
13
13
347
10
10
219
39
5
263
—
105
2
96
1
—
204
204
15
2
16
943
836
101
62
4
—
7
4
—
1
1,015
1,958
72
38
38
110
107
14
203
323
3
3
327
12
12
221
42
6
270
—
111
2
85
1
—
199
199
15
2
17
933
809
96
65
4
—
—
—
—
1
974
1,908
6
—
—
6
—
34
21
56
—
—
56
10
10
—
—
10
10
—
—
—
—
—
—
—
—
2
—
2
85
4
—
—
—
2
2
—
4
—
12
97
6
4
4
10
—
36
20
56
—
—
56
8
8
—
—
5
5
—
—
—
—
—
—
—
—
3
—
3
82
4
—
1
—
3
—
—
1
—
8
90
7
5
5
11
—
37
19
56
—
—
56
11
11
—
—
7
7
—
—
—
—
—
—
1
1
3
—
3
88
4
—
3
—
3
—
—
—
—
10
99
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 2017, BP renewed its onshore concession of the United Arab Emirates that grants BP 10% interest in ADCO onshore concession. It also decreased its interest in Magnus field in North
Sea and completed the formation of Pan American Energy Group (PAEG) (BP 50%, Bridas Corporation 50%), which is a combination of Pan American Energy and Axion Energy with an
effective decrease in interest. 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.
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 BP holds interests, through associates, in offshore concessions in Abu Dhabi which expire in 2018.
g Includes 3 net mboe/d of NGLs from processing plants in which BP has an interest (2016 3mboe/d and 2015 4mboe/d).
Because of rounding, some totals may not agree exactly with the sum of their component parts.
262
«See Glossary
BP Annual Report and Form 20-F 2017
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
Azerbaijan
Western Indonesiab
India
Oman
Total Rest of Asia
Total Asia
Australiab
Eastern Indonesiab
Total Australasia
Total subsidiariesc
Equity-accounted entities (BP share)
Rosneft (Russia, Canada, Egypt, Venezuela, Vietnam)
Argentina
Bolivia
Norwayb
Angola
Western Indonesia
Total equity-accounted entitiesc
Total subsidiaries and equity-accounted entities
million cubic feet per day
BP net share of productiona
2017
2016
2015
182
—
—
182
1,467
186
5
1,659
9
9
1,667
1,936
1,936
745
205
949
232
—
60
79
371
371
426
357
783
5,889
1,308
329
89
53
77
—
1,855
7,744
170
82
82
252
1,476
173
6
1,656
10
10
1,666
1,689
1,689
305
208
513
245
35
84
—
363
363
451
369
820
5,302
1,279
354
95
12
18
15
1,773
7,075
155
111
111
266
1,353
168
7
1,528
10
10
1,538
1,922
1,922
402
187
589
219
48
113
—
380
380
447
354
801
5,495
1,195
341
93
—
—
21
1,651
7,146
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 2017, BP decreased its interest in Magnus field in North Sea and completed the formation of Pan American Energy Group (PAEG) (BP 50%, Bridas Corporation 50%), which is a
combination of Pan American Energy and Axion Energy with an effective decrease in interest.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.
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 2017
«See Glossary
263
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
Europe
UK
Rest of
Europe
North
America
South
America
Africa
Asia
Australasia
Rest of
North
Americab
US
Russia
Rest of
Asia
53.67
32.77
5.09
42.80
25.70
4.50
52.42
30.66
7.83
—
—
—
—
—
—
—
—
—
—
—
—
40.16
20.16
4.19
50.68
28.20
6.49
55.08
—
5.78
50.71
—
5.16
—
—
—
49.98
22.42
2.36
39.65
14.71
1.90
49.84
14.80
2.10
—
—
—
—
—
—
—
—
—
36.80
—
—
26.11
—
—
26.71
—
—
—
—
—
—
—
—
—
—
—
55.44
26.79
2.25
45.64
21.40
1.72
53.19
27.66
2.67
49.97
—
4.49
48.88
34.51
4.21
54.24
13.17
4.35
53.61
36.48
3.82
40.83
21.30
3.89
49.09
31.94
4.40
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
45.66
N/A
1.63
36.36
N/A
1.39
44.78
N/A
1.48
52.88
—
3.44
39.29
—
3.39
49.33
—
5.35
15.61
—
—
12.92
—
6.11
16.87
—
7.56
53.26
39.39
6.14
41.52
32.70
5.71
50.64
36.69
7.35
—
—
—
—
—
—
—
—
—
Total
group
average
51.71
26.00
3.19
39.99
17.31
2.84
49.72
20.75
3.80
42.33
—
2.47
34.04
34.51
2.20
41.49
13.17
2.35
Subsidiaries
2017
Crude oilc
Natural gas liquids
Gas
2016
Crude oilc
Natural gas liquids
Gas
2015
Crude oilc
Natural gas liquids
Gas
Equity-accounted
entitiesd
2017
Crude oilc
Natural gas liquidse
Gas
2016
Crude oilc
Natural gas liquidse
Gas
2015
Crude oilc
Natural gas liquidse
Gas
Average production cost per unit of productionf
$ per unit of production
Europe
UK
Rest of
Europe
14.58
14.80
22.95
—
—
—
—
13.72
13.80
10.33
10.41
—
North
America
South
America
Africa
Asia
Australasia
US
8.68
10.20
11.84
—
—
—
Rest of
North
America
15.02
21.79
43.56
—
—
—
Russia
—
—
—
3.19
2.46
2.60
Rest of
Asia
6.37
7.08
11.22
3.27
3.67
4.59
2.79
2.62
2.88
—
—
—
4.41
4.21
5.44
11.92
10.66
12.10
6.47
9.34
11.02
—
—
—
Total
group
average
7.11
8.46
10.46
4.32
3.57
3.93
Subsidiaries
2017
2016
2015
Equity-accounted
entities
2017
2016
2015
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 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.
e Natural gas liquids for Russia are included in crude oil.
f Units of production are barrels for liquids and thousands of cubic feet for gas. Amounts do not include ad valorem and severance taxes.
264
«See Glossary
BP Annual Report and Form 20-F 2017
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 provision
2017
2016
—
441
487
22
249
—
487
564
27
262
(228)
(804)
$ million
2015
5,452
521
733
34
305
972
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 $441 million in 2017 (2016
$487 million) showed an overall decrease of 9% which was primarily
due to lower expenditures associated with BP's share of the TAPS
pipeline.
Environmental capital expenditure in 2017 was lower overall than in
2016, largely due to lower spend as a result of the completion of the
installation of the new LPG refrigeration plant for the North Sea
Forties Pipeline System in the previous year and lower spend on
Kuparuk field in Alaska driven by lower activity.
Clean-up costs decreased to $22 million in 2017 compared with $27
million in 2016, primarily due to decreased contractual rates and
overall cost reductions. The numbers of oil spills are broadly similar
and while the volume of oil has increased, this includes releases to
secondary containment which do not reach the environment.
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 2017 included $8 million in
respect of provisions for new sites (2016 $7 million and 2015 $6
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 2017, the net decrease in the decommissioning provision, similar to
the decrease in 2016, was a result of detailed reviews of expected
future costs, partially offset by 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 21.
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.
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 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 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,
BP Annual Report and Form 20-F 2017
«See Glossary
265
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
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 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.
On 1 June 2017, the US announced that it will withdraw from the
Paris Agreement. This includes suspending the implementation of the
US’s NDC and funding for the Green Climate Fund. The process for
withdrawal can be completed no earlier than 4 November 2020.
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. At COP23, held in
November 2017 in Bonn, the parties met to continue the negotiations;
amongst other things, the parties agreed to launch the 2018 Talanoa
Dialogue to review collective efforts in relation to progress towards
the Paris Agreement objectives and to inform the preparation of
NDCs, and to convene stocktakes on pre-2020 implementation and
ambition at COP24 and 25.
More stringent national and regional measures relating to the
transition to a lower carbon economy can be expected in the future.
These measures could increase BP’s production costs for certain
products, increase compliance and litigation costs, increase demand
for competing energy alternatives or products with lower-carbon
intensity, and affect the sales and specifications of many of BP’s
products. Further, such measures could lead to constraints on
production and supply and access to new reserves, particularly due to
the long term nature of many of BP’s projects. 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
Executive Order (EO) 13783 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. EO 13783 also instructed
the Department of Interior (DOI) to review and possibly suspend,
revise or rescind the Bureau of Land Management (BLM) methane
rule. The EPA and the DOI are taking steps to implement these
aspects of EO 13783 and legal challenges have been brought by
some US states and private parties regarding these proposed
changes.
• Greenhouse gas (GHG) emissions are currently regulated in a
number of ways under the CAA. As noted above, as a result of EO
13783, some of these regulations may be suspended, revised or
rescinded resulting in complex compliance challenges for our
affected businesses.
– Stricter GHG regulations, stricter limits on sulphur in fuels,
emissions regulations in the refinery sector and a revised lower
ambient air quality standard for ozone, finalized by the EPA in
October 2015, are affecting our US operations.
– 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. The Trump
administration is seeking to rescind both of these rules but the
timing of any rescission is subject to legal challenges and
regulatory requirements.
– 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 revised or rescinded.
– States may also have separate, stricter air emission laws in
addition to the CAA. Despite the US withdrawal from the Paris
Agreement, a number of US states, cities and private
organizations remain committed to meeting Paris Agreement
goals. A number of states also belong to or are considering
joining carbon trading markets (e.g. California).
• 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
266
«See Glossary
BP Annual Report and Form 20-F 2017
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. California and a
number of other states impose different, stricter GHG emission
limits on vehicles. These varying standards impact BP’s product mix
and overall demand.
• 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.
• On 9 October 2017 the EPA announced its intention to repeal the
Clean Power Plan (CPP) which was an important element of the
Obama administration’s Climate Action Plan. The CCP regulations
are currently stayed pending resolution of existing legal challenges;
the EPA may decline to defend certain of these legal challenges.
The EPA’s repeal proposal is likely to face legal challenges as well
and repeal of the CPP regulations, or adoption of a narrower
replacement rule, may not occur until well after 2018. The outcome
with respect to these rules will affect electricity generation
practices and prices, reliability of electricity supply, and regulatory
requirements affecting other GHG emission sources in other
sectors and have potential impacts on combined heat and power
installations.
• 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 by 40-45% from 2012 levels by 2025 that
would apply to existing sources in the sector. In January 2017 the
BLM’s methane rule, aimed at limiting methane emissions from oil
and gas operations on federal lands also came into effect.
Following the Trump administration’s EO 13783, on 16 June 2017
the EPA proposed a two-year stay of portions of the methane
regulations for new and modified oil and gas sources. In December
2017, the BLM proposed a 13 month delay of its methane rule. In
February 2018, a federal court in California ruled against that 13
month delay. Also in February 2018, the BLM proposed to revise its
methane rule. The final outcome of the rule revisions and legal
challenges with respect to implementation of EO 13783 regarding
these EPA and BLM rules is uncertain, but may affect our US
upstream businesses’ management of methane emissions in the
US.
• A number of states, municipalities and regional organizations have
responded to current and proposed federal changes in
environmental regulation and 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, and
the State of Washington adopted a carbon cap rule 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). By 2021, the European passenger fleet emissions
target for new vehicles will be 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.
• 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$30/tonne
to a technology fund. In addition, the Alberta government
implemented an economy-wide price of carbon policy 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 line with Federal backstop pricing). Changes were also made to
electricity generation sources, limits on overall oil sands emissions,
and sector specific output-based-allocations (performance
standards) have been set such that compliance requirements will
now be based on emission intensity relative to top quartile
performance in each sector. Compliance obligations, if required,
can be satisfied through emission reductions, payments to the
government or use of offsets. The Canadian federal government
has announced climate change policy goals including a national
backstop carbon price starting at C$10/tonne in 2018 and escalating
to C$50/tonne by 2022 (or equivalent system for provinces with
cap-and-trade systems), with implementation of the price and
associated large emitters pricing system (modelled on the Alberta
output-based-allocation system), use of any funds generated and
outcome reporting being managed by each province.
• China is operating emission trading pilot programmes in five cities
and two provinces and some selected non-pilot provinces have also
been approved to engage in emission trading. One of BP's
subsidiaries and one of BP’s joint venture« companies in China are
participating in these schemes. A plan on establishing the
nationwide carbon emissions trading market (covering power
sector only) was promulgated in December 2017 by the National
Development and Reform Commission, which will not supersede
the above seven pilot programmes immediately but allow those
pilot schemes to be incorporated into the national scheme
gradually. In July 2016, China carried out pilot programmes on
BP Annual Report and Form 20-F 2017
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compensation for and trading of energy quotas in four provinces
which may be further expanded in or after 2020. In January 2017, a
nationwide pilot scheme on the issuance and voluntary purchase
and trading of renewable energy green power certificates was
launched and it is expected that the evaluation on renewable
energy power quotas and mandatory trading of green power
certificates will be launched in 2018.
• 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. In addition,
China has also introduced a mandate for sales of new energy
vehicles (NEVs) commencing in 2020. This will accelerate NEV
penetration into the light vehicle sector and impact light fuel
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 50.
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 21 for
information on provisions for environmental restoration and
remediation.
A number of pending or anticipated governmental proceedings
against certain BP group companies under environmental laws could
result in monetary or other sanctions. Group companies are also
subject to environmental claims for personal injury and property
damage alleging the release of, or exposure to, hazardous
substances. The costs associated with future environmental
remediation obligations, governmental proceedings and claims could
be significant and may be material to the results of operations in the
period in which they are recognized. We cannot accurately predict the
effects of future developments, such as stricter environmental laws
or enforcement policies, or future events at our facilities, on the
group, and there can be no assurance that material liabilities and
costs will not be incurred in the future. For a discussion of the group’s
environmental expenditure, see page 265.
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 2017, the Trump administration has
issued a number of Executive Orders (EO) 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 legal challenges 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. State law analogues to NEPA could also limit or delay our
projects. On 15 August 2017 the Trump administration issued EO
13807 which directs federal agencies to take certain actions to
streamline the NEPA process although the effect of EO 13807 on
our operations remains uncertain.
• 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 EPA is currently reassessing the
Obama Administration’s mid-term evaluation (MTE) of the 2022-25
automobile fuel economy (CAFE) standards. A reassessment of the
standards could change original equipment manufacturer (OEM)
compliance plans and consequently motor fuel demand. The EPA is
expected to complete its assessment in April 2018.
• The Clean Water Act regulates wastewater and other effluent
discharges from BP’s facilities, and BP is required to obtain
discharge permits, install control equipment and implement
operational controls and preventative measures.
• The Resource Conservation and Recovery Act regulates the
generation, storage, transportation and disposal of wastes
associated with our operations and can require corrective action at
locations where such wastes have been disposed of or released.
• The Comprehensive Environmental Response, Compensation, and
Liability Act (CERCLA) can, in certain circumstances, impose the
entire cost of investigation and remediation on a party who owned
or operated a site contaminated with a hazardous substance, or
arranged for disposal of a hazardous substance at a site. BP has
incurred, or is likely to incur, liability under 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 EPA has promulgated 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. In 2017, the
EPA finalized details regarding the process and requirements for
execution of the TSCA inventory reset. BP is currently collecting
the requisite information for submission to the EPA to assure that
the chemical substances that are: (i) contained in our manufactured
or imported products; (ii) used to manufacture our products; and
(iii) used in our operations, continue to be included in the US TSCA
inventory.
• 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.
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• 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, the 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.
• 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 Energy Efficiency Directive (EED) was adopted in 2012. It
requires EU member states to implement an indicative 2020
energy saving target and apply a framework of measures as part of
a national energy efficiency programme, including mandatory
energy efficiency audits. 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 EED. A revision to the
EED was proposed by the European Commission in November
2016, which includes a new energy efficiency target for 2030.
• The Industrial Emissions Directive (IED) 2010 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 sector
specific and cross-sector Best Available Technology (BAT)
Conclusions, such as the BAT Conclusions for the refining sector,
for large combustion plants as well as common waste water and
waste gas treatment and management systems in the chemical
sector. These may result in requirements for BP to further reduce
its emissions, particularly its air and water emissions.
• The Medium Combustion Plants Directive (MCPD) came into force
on 18 December 2015, with a deadline for implementation by
member states of 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 2016 entered into force on
31 December 2016, replacing earlier legislation. It introduces
stricter emissions limits from 2020 and 2030, with new indicative
national targets applying from 2025. The new Directive must be
implemented by EU member states by 1 July 2018.
• The EU regulation on ozone depleting substances 2009 (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. The Kigali Amendment to the Montreal Protocol
(which aims to reduce hydrofluorocarbons) will come into force
from 1 January 2019. In addition, the EU regulation on fluorinated
GHGs with high global warming potential (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 2006 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 (i.e. 100 tonnes per annum or greater), 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. In addition,
BP’s facilities and operations in several EU countries have
undergone REACH compliance inspections by the competent
authority for the respective EU member state.
• 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 review 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 is upgrading its
water treatment facilities to meet consent levels agreed 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 upgraded 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 2017, 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
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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 are 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 entered into force in September 2017.
• The Convention for the Protection of the Marine Environment of
the North-East Atlantic (OSPAR), entered into force in March 1998,
is an international convention which aims to protect the marine
environment of the North-East Atlantic. OSPAR has 16 contracting
parties, including the UK Government. Work carried out in
accordance with OSPAR is managed by the OSPAR Commission,
which is made up of government representatives of the 15
contracting parties and the European Union. OSPAR
Recommendation 2001/1 relates to the management of produced
water from offshore installations in the North Sea. The OSPAR
Commission has set a target of a 15% reduction in the total
quantity of oil in produced water discharged, and more recently,
guidelines for the implementation of a risk-based approach to the
management of produced water discharges from offshore
installations were adopted (OSPAR Recommendation 2012/5).
• The EU shipping monitoring, reporting and verification (MRV)
regulation entered into force in July 2015 and is aimed at gathering
data on CO2 emissions based on ships’ fuel consumption. It is
considered the first step of a staged approach for the inclusion of
maritime transport emissions in the EU’s GHG reduction
commitment. In parallel, through amendments to MARPOL Annex
VI, the IMO Data Collection System (DCS) for collecting and
analysing fuel consumption data is due to come into effect in
March 2018.
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. All federal and state claims in relation to the Incident have
now been settled or dismissed and the five-year probation period
under the criminal plea agreement with the US Department of Justice
came to an end in January 2018. The remaining proceedings arising
from the Incident are discussed below. For further details of the
consent decree and settlement agreement with the United States
federal government and five Gulf Coast states, see ‘Legal
proceedings’ in BP Annual Report and Form 20-F 2015.
PSC settlements
PSC settlements – Economic and Property Damages Settlement
Agreement
The Economic and Property Damages Settlement resolved
certain economic and property damage claims. 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 was 8 June 2015.
Following numerous court decisions, on 31 March 2015 the
district 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 required 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. The PSC appealed this decision and,
on 22 May 2017, the Fifth Circuit issued an opinion upholding the
policy in part and reversing the policy in part. The Fifth Circuit
ordered that the portion of the policy upheld, which covers the
substantial majority of the remaining business economic loss
claims, be applied as the governing methodology for all applicable
business economic loss claims. On 25 May 2017, 13 June 2017,
and 5 July 2017, the district court issued a series of orders
instructing the court supervised settlement programme on how
to implement the Fifth Circuit’s opinion. On 10 August 2017, the
district court denied BP’s motion to clarify or reconsider its
orders. BP appealed all of these orders and decisions on 8
September 2017 and that appeal has been consolidated with four
appeals filed by claimants in early to mid-September 2017. Those
four claimant appeals also challenge the same set of district court
orders and decisions, albeit raising different issues than are raised
by BP’s appeal. These appeals are currently pending before the
Fifth Circuit.
On 17 March 2017, the district court issued an order regarding
approximately 150 claimants in the economic and property
damages claims process whose claims had been subject to a
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hold pending the development of agreed-upon guidance that the
claims administrator shall apply in making compensation
determinations that adhere to the moratoria exclusion in the
Economic and Property Damages Settlement. The court ordered
that those claimants with claims remaining in moratoria hold
without a resolution of their claims had the opportunity to opt that
claim out from the claims process by 24 April 2017 and pursue
the claim in litigation. On 19 July 2017 the district court issued an
order finding that 13 plaintiffs validly opted claims out of
moratoria hold and complied with the relevant court order, and
that those plaintiffs’ claims under the Oil Pollution Act of 1990
(OPA 90) would be subject to further proceedings in MDL 2179
(see ‘Other civil complaints - economic loss’ below).
As a result of significantly higher average claims determinations
issued by the court supervised settlement programme in the
fourth quarter of 2017 and the continuing effect of the May 2017
Fifth Circuit opinion, the provision for the costs associated with
the Economic and Property Damages Settlement was increased
in the fourth quarter of 2017. The amounts ultimately payable may
differ from the amount provided and the timing of payments is
uncertain. 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 37,225. As of 26 January
2018, 27,592 claims (comprising 22,796 SPC and 4,796 PMPC
only) have been approved for compensation totalling
approximately $67 million; 9,546 claims have been denied; and
87 claims are pending determination. In addition, there are 16
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.
Other civil complaints – economic loss
Following various court orders by the district court in MDL 2179 in
2016, 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. However, several groups of plaintiffs whose claims
were dismissed by the district court have four appeals pending in
the Fifth Circuit, and briefing of those appeals is currently
underway. In addition, on 22 March 2017, BP moved to dismiss
the claims of certain plaintiffs with economic loss claims on the
grounds that they had previously released their claims or had
failed to meet the OPA 90 requirement that plaintiffs present their
claims to the Responsible Party prior to filing suit. On 21
September 2017, the district court granted in part BP’s motion
regarding presentment and, on 20 October 2017, the district court
granted in part BP’s motion regarding release; certain of the
plaintiffs have brought appeals challenging these orders. On 11
January 2018, the district court issued an order requiring all
remaining plaintiffs in MDL 2179 with economic loss or property
damage claims to file by 11 April 2018 a verified sworn statement
regarding the actual damages each such plaintiff seeks in its
pending litigation and an explanation of how those alleged
damages were causally related to the Incident.
Following the resolution in 2016 of the vast majority of those
economic claims opted out of and/or excluded from of the 2012
PSC settlement, referred to above, in 2017 the district court
addressed the maritime claims. 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. On 19 July 2017 the district
court issued an order finding that 215 plaintiffs, who had complied
with the court’s previous orders, had also complied with the
court’s 22 February 2017 order. The district court held that those
plaintiffs' claims would be subject to further proceedings in MDL
2179 under OPA 90 and under general maritime law. The court
dismissed with prejudice all other claims for economic loss
brought by private plaintiffs under general maritime law and
certain of these plaintiffs moved for reconsideration. On 8
November 2017, the district court denied most of the motions for
reconsideration of the 19 July 2017 order but granted in part
several of the motions, ruling that an additional six plaintiffs had
complied with the 22 February 2017 order regarding general
maritime law claims and thus that their claims under general
maritime law were not dismissed. The district court also ruled that
an additional five plaintiffs had complied with previous of the
court’s orders but not the 22 February 2017 order regarding
general maritime law claims and thus would be subject to further
proceedings in MDL 2179 on their claims under OPA 90, but not
their claims under general maritime law. Five groups of plaintiffs
whose motions were denied by the 8 November 2017 order filed
appeals in the Fifth Circuit, and those appeals remain pending.
Other civil complaints – personal injury
On 18 July 2017, the district court in MDL 2179 issued an order
identifying 960 plaintiffs whose claims for post-explosion clean-
up, medical monitoring and personal injury claims occurring after
the Incident will be subject to further proceedings in MDL 2179.
The court dismissed with prejudice any other private plaintiffs’
post-explosion clean-up, medical monitoring and personal injury
claims and certain of these plaintiffs moved for reconsideration.
On 6 December 2017, the district court denied most of the
motions for reconsideration, granting some in part, and certain
groups of plaintiffs whose motions were denied have appealed
the order to the Fifth Circuit. Accordingly the vast majority of
post-explosion clean-up, medical monitoring and personal injury
claims from individuals that either opted out of the 2012
settlement with the Plaintiffs’ Steering Committee and/or were
excluded from that settlement have been dismissed.
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
Following various legal proceedings, a class of post-explosion ADS
purchasers from 26 April 2010 to 28 May 2010 was certified, and in
June 2016, BP agreed with plaintiffs’ representatives to settle the
class claims for $175 million, 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, and all settlement payments
were made in 2017.
Individual securities litigation
From April 2012 to April 2016, 37 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 28 September 2016, defendants filed a
motion to dismiss certain claims against certain defendants in 20 of
the individual securities cases. In a decision issued on 30 June 2017,
the district court dismissed many of plaintiffs’ claims based on
alleged losses from holdings (as opposed to purchases) of BP
ordinary shares and dismissed claims based on all but one of the
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alleged misstatements that had not been addressed by the court’s
prior decisions. On 17 July 2017, defendants moved for
reconsideration on the one alleged misstatement that the district
court did not dismiss; on 28 July 2017, plaintiffs opposed that motion
and cross-moved for reconsideration on three alleged misstatements
that the court dismissed. On 19 January 2018, the court denied
defendants’ motion and plaintiffs’ cross-motion. On 2 June 2017,
defendants moved to dismiss one action in which plaintiffs seek to
pursue an English law negligent misstatement claim based upon
seven meetings with BP employees, on behalf of a class of all
institutional investors who engaged and delegated full investment
authority to Mondrian Investment Partners.
On 7 December 2017, plaintiffs filed an amended complaint. On 9
February 2018, defendants filed a renewed motion to dismiss that
amended complaint. The plaintiffs in an individual action asserting
only Exchange Act claims voluntarily dismissed their case on 15
February 2018. Further, on 16 February 2018, defendants moved for
judgment on the pleadings dismissing, as time-barred, all Exchange
Act claims in the remaining individual actions based on alleged
misstatements made more than five years before the filing of the
actions. The plaintiffs in three cases have elected to participate in the
ADS securities class action settlement and, accordingly, their
individual cases were dismissed.
Canadian class actions
Following various legal proceedings, on 26 February 2016, a plaintiff
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 filed a motion in the
Court of Appeal for Ontario to lift a stay on the action. The plaintiff’s
motion was granted on 29 July 2016. On 23 June 2017, BP moved for
summary judgment and on 1 September 2017 the court granted in
part and denied in part that motion, limiting the case to three alleged
misstatements and narrowing the class period. On 29 September
2017, plaintiff filed a notice of appeal of that decision.
On 15 December 2017, plaintiffs in a purported class action that was
filed in 2012 in Alberta, Canada, and not pursued, filed an application
seeking advice and directions regarding continuing their action; a
conference on that application has not yet been scheduled.
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. On 5 April 2017, BP moved to dismiss the State of Yucatan’s
claims, and the court granted BP's motion to dismiss on 6 March
2018.
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. The
claims in this civil action were resolved by agreement effective 15
February 2018.
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 certifying the class on 2 December 2015, BP filed a
constitutional challenge (amparo) in Mexico on 13 April 2016 asserting
that BP has never been formally served with process in the class
action. This amparo was denied on 22 November 2016 and the appeal
was also denied on 17 August 2017. BP has not been formally served
with the class certification decision, which is required before the
action can go forward.
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 against BPXP, BPAPC, and other purported BP
subsidiaries. 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. A Mexican BP entity was served with
the complaint on 23 January 2018 and opposed class certification and
sought dismissal on 30 January 2018 on the basis that the entity did
not exist at the time of the spill. BPXP was formally served with the
action on 8 December 2017. BPXP opposed class certification and
sought dismissal on 1 February 2018, principally on the basis that that
no oil reached Mexican waters or land and there was no economic or
environmental harm in Mexico.
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.
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
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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.
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 made similar allegations in
addition to individual claims. In January 2018 the parties reached a
settlement pursuant to which BP, while denying liability, agreed to pay
$102 million to the state of California.
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. BP appealed and oral argument was
heard in August 2017. The Oregon Court of Appeal has not yet issued
its decision. 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
Comprehensive Plan of Action (JCPOA). As a result of the JCPOA, 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.
The North Sea Rhum field (Rhum) is owned under a 50:50
unincorporated joint arrangement between BP and Iranian Oil
Company (U.K.) Limited (IOC). BP obtained an updated OFAC licence
in relation to the continued operation of Rhum on 29 September 2017.
On 21 November 2017, BP announced that it has agreed to sell
certain of its assets in the North Sea, including its ownership stake,
and the transfer of its role as operator, in the Rhum joint arrangement
to Serica Energy plc. The sale and transfer of ownership is subject to
regulatory and third-party approvals and is expected to complete in
the third quarter of 2018.
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 the Iran Threat Reduction and Syria Human Rights Act
of 2012 (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 sells lubricants in Cuba through a 50:50 joint arrangement and
trades in small quantities of lubricants.
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. In August 2017, new Russia related
sanctions were passed in the US which target among other things: (i)
Russian energy export pipelines; (ii) privatisation of state owned
assets in Russia; and (iii) certain international offshore Arctic,
deepwater and/or shale E&P oil projects. We are not aware of any
material adverse effect on our current income and investment in
Russia or elsewhere.
BP has registered and paid required fees to maintain registrations of
patents and trade marks in Sanctioned Countries.
BP Annual Report and Form 20-F 2017
«See Glossary
273
to Iran and other meetings in connection with various business
opportunities.
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
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 2017 filed with the SEC.
For further details of the Consent Decree and the Settlement
Agreement, see Legal proceedings in BP Annual Report and Form 20-
F 2015.
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 2017 and the group
percentage of ordinary share capital see Financial statements – Note
35. For information on significant joint ventures« and associates« of
the group see Financial statements – Notes 14 and 15.
Related-party transactions
Transactions between the group and its significant joint ventures and
associates are summarized in Financial statements – Note 14 and
Note 15. In the ordinary course of its business, the group enters into
transactions with various organizations with which some of its
directors or executive officers are associated. Except as described in
this report, the group did not have any material transactions or
transactions of an unusual nature with, and did not make loans to,
related parties in the period commencing 1 January 2017 to 14 March
2018.
BP has equity interests in non-operated joint arrangements«with air
fuel sellers, resellers, and fuel delivery services around the world.
From time to time, the joint arrangement operator or other partners
may sell or deliver fuel to airlines from Sanctioned Countries or flights
to Sanctioned Countries, without BP's involvement.
BP has no control over the activities non-controlled associates may
undertake in Sanctioned Countries or with persons from Sanctioned
Countries.
Disclosure pursuant to Section 219 of ITRA
To our knowledge, none of BP’s activities, transactions or dealings are
required to be disclosed pursuant to ITRA Section 219, with the
following possible 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 (IOC). During 2017, BP recorded gross revenues of $124
million related to its interests in Rhum. BP had a net profit of $42
million for the year ended 31 December 2017, including an
impairment reversal of $16.7 million in the second quarter of 2017.
As noted above, BP has agreed to sell its ownership stake in the
Rhum joint arrangement and transfer its role as operator to Serica
Energy plc.
• In November 2017, BPEOC entered into an agreement with IOC for
the sale and purchase of an IOC entitlement to Forties blend crude
oil. The parties agreed to set off the purchase price – £29.89 million
($40.2 million equivalent) – against IOC’s share of operating costs
incurred or to be incurred by BPEOC as operator of the Rhum field
under the Rhum joint operating agreement. 604,976 net barrels of
Forties blend crude oil was loaded at a North Sea terminal in
January 2018 and delivered to BP’s Rotterdam refinery. Upon
delivery at BP’s Rotterdam refinery, the Forties blend crude oil 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 does not expect to enter into any further
similar arrangements with IOC in relation to the Rhum field.
• A third-party UK entity’s purchase of IOC’s share of Rhum natural
gas was settled by an assignment of receivables on 13 October
2017 pursuant to which BPEOC received £15 million ($19.3 million
equivalent) from the UK entity, which would otherwise have been
payable to Naftiran Intertrade Company (NICO) Limited. The £15
million ($19.3 million equivalent) has also been set off against IOC’s
share of operating costs incurred by BPEOC as operator of the
Rhum field under the Rhum joint operating agreement. BP does
not expect to enter into any further arrangements with NICO in
relation to the Rhum field.
• In December 2016, BP Singapore Pte. Limited (BPS) purchased a
shipment of South Pars condensate from the National Iranian Oil
Company (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 leases an office in Tehran. The office is used for
administrative activities. In 2017, rental tax payments associated
with the Tehran office, with an aggregate US dollar equivalent value
of approximately $19,000, 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 2017, 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
$12,000. In addition, certain BP employees met with Iranian
government officials and other Iranian nationals outside of Iran. No
gross revenues or net profits were attributable to these activities,
save where otherwise disclosed, and BP intends to continue visits
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BP Annual Report and Form 20-F 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, with the exception of the
chairman. 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 77-89). 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 77). 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 2017 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 2017 was effective.
BP Annual Report and Form 20-F 2017
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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 2017 has been audited by
Ernst & Young, an independent registered public accounting firm, as
stated in their report appearing on page 124 of BP Annual Report and
Form 20-F 2017.
The audit committee evaluates the performance of the auditors each
year. The audit fees payable to Ernst & Young are reviewed by the
committee in the context of other global companies for cost
effectiveness. The committee keeps under review the scope and
results of audit work and the independence and objectivity of the
auditors. External regulation and BP policy requires the auditors to
rotate their lead audit partner every five years. See Financial
statements – Note 34 and Audit committee report on page 82 for
details of fees for services provided by auditors.
Directors’ report information
This section of BP Annual Report and Form 20-F 2017 forms part of,
and includes certain disclosures which are required by law to be
included in, the Directors’ report.
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.
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 services. The
policies provide for pre-approval by the audit committee of specifically
defined audit, audit-related, non-audit 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 non-audit tax services
provided by the audit firm from 2017 onwards are prohibited.
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); 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, 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 UK
Financial Reporting Council, the audit committee reviewed and
updated its policies with effect from 1 January 2017. The defined
maximum level for pre-approval has been reduced in line with FRC
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.
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 2017.
During the year, a review of the terms and scope of the policy was
undertaken. The policy was renewed during 2017 and continued into
2018. 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 55, Liquidity and capital resources on page 251
and Financial statements – Notes 27 and 28.
Exposure to price risk, credit risk, liquidity risk and
cash flow risk
The disclosures in relation to exposure to price risk, credit risk,
liquidity risk and cash flow risk are included in Financial statements –
Note 27.
Important events since the end of the financial year
Disclosures of the particulars of the important events affecting BP
which have occurred since the end of the financial year are included in
the Strategic report as well as in other places in the Directors’ report.
Likely future developments in the business
An indication of the likely future developments of the business is
included in the Strategic report.
Research and development
An indication of the activities of the company in the field of research
and development is included in Innovation in BP on page 44.
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 53.
276
«See Glossary
BP Annual Report and Form 20-F 2017
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
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 in BP Annual
Report and Form 20-F 2015.
Greenhouse gas emissions
The disclosures in relation to greenhouse gas emissions are included
in Sustainability – Climate change on page 50.
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
150
Not applicable
277
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 and circumstances -
with respect to the financial condition, results of operations and
businesses of BP and certain of the plans and objectives of BP with
respect to these items. These statements may generally, but not
always, be identified by the use of words such as ‘will’, ‘expects’, ‘is
expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’,
‘believes’, ‘anticipates’, ‘plans’, ‘we see’ or similar expressions. In
particular, among other statements, (i) certain statements in the
Chairman’s letter (pages 6-7), the Group chief executive’s letter
(pages 8-9), the Strategic report (inside cover and pages 1- 58),
Additional disclosures (pages 247-278) and Shareholder information
(pages 279 - 288), including but not limited to statements under the
headings ‘The changing world of energy’, ‘How we run our business’,
‘Our strategy’ and ‘Global energy markets’ and including, but not
limited to, statements regarding plans and prospects relating to
future value creation, near and long-term growth, organic capital
expenditure, balance sheet strength, maintaining a robust cash
position, operating cash flow and margins, capital discipline, growth
in sustainable free cash flow and shareholder distributions and future
dividend and optional scrip dividend payments; expectations
regarding world energy demand, including the growth in relative
demand for renewables, oil and gas, and the proportional growth of
renewables; plans and expectations regarding BP’s portfolio including
to grow oil and gas; plans to be the low-cost developer and producer
in each basin; plans and expectations with regard to new
technologies including their efficiency and impact on production;
plans to close all physical datacentres over several years; expectations
regarding carbon regulations in 2020 and the share of BP’s direct
emissions subject to such regulations; plans and expectations to
reduce emissions by 3.5 million tonnes by 2025; plans to build a
lubricants blend plant in China; plans to grow third-party technology
licensing income; plans and expectations with regard to the Butamax
joint venture and partnership with Lightsource; plans and
expectations regarding annual charges in Other businesses and
corporate, proceeds from divestments and disposals; expectations
regarding the determination of business economic loss claims in
respect of the 2012 PSC settlement and expectations with respect to
the timing and amount of future payments relating to the Gulf of
Mexico oil spill including 2012 PSC settlement payments; plans and
expectations regarding sales commitments of BP and its equity-
accounted entities; expectations regarding underlying production and
capital investment; plans and expectations with respect to gearing
including to target gearing within a 20-30% band; expectations
regarding oil prices; expectations regarding the return on average
capital employed; plans with regard to BP’s exploration budget;
expectations that managed base decline remains between 3-5%;
plans and expectations regarding resiliency of downstream
businesses; plans and expectations with respect to BP’s retail
network including to have 1,500 sites in Mexico by 2021;
expectations regarding the effective tax rate in 2018; plans to produce
900,000 boe/d from new projects by 2021 and expectations regarding
operating cash margins of this production; plans to start up six
projects in 2018; plans and expectations regarding investment,
development, and production levels and the timing thereof with
respect to projects and partnerships in Alaska, Angola, Argentina,
Australia, Azerbaijan, Brazil, China, Egypt, Georgia, India, Indonesia,
Mexico, Mauritania, Russia, Senegal, Turkey, Trinidad & Tobago, Oman,
the UK North Sea, the Gulf of Mexico, and the continental United
States; expectations regarding the Trans Anatolian Natural Gas
Pipeline; plans and expectations regarding social investment; plans
and expectations regarding relationships with governments,
customers, partners, suppliers and communities; plans and
expectations regarding renewable energy, including planned
investments; plans and expectations regarding plant reliability and
base decline; plans and expectations regarding the Tangguh gas
facility, including the facility’s role in supporting Indonesia’s energy
demands, production from train 3, and the target to source 38% of
services and materials from local suppliers; expectations regarding
discounts for North American heavy crude oil, refining margins and
BP Annual Report and Form 20-F 2017
«See Glossary
277
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.
refining turnarounds; plans to undertake joint exploration and
development with Rosneft; expectations regarding payments under
contractual obligations; plans and expectations with regard to the
strategic aims of Air BP and the lubricants business; 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; policies and goals related to risk management plans;
plans regarding activities, dealings, transactions relating to Iran; plans
and expectations regarding the timing and payment of proceeds from
the sale of BP’s stake in Magnus, Sullom Voe Terminal and Bruce
assets; plans and projections regarding oil and gas reserves, including
the turnover time of proved undeveloped reserves to proved
developed reserves; expectations regarding the costs of
environmental restoration programmes; 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; 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
59-89) and the Directors’ remuneration report (pages 90-112) with
regard to the anticipated future composition of the board of directors
and the effects thereof; 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 and expectations
regarding directors’ share ownership and remuneration; plans
regarding the implementation of the remuneration policy in 2018; and
goals, activities 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 and policies, including related
to climate change; changes in social attitudes and customer
preferences; 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; amounts
ultimately determined to be payable and the timing of payments
relating to the Gulf of Mexico oil spill; exchange rate fluctuations;
development and use of new technology; recruitment and retention
of a skilled workforce; the success or otherwise of partnering; the
actions of competitors, trading partners, contractors, subcontractors,
creditors, rating agencies and others; our access to future credit
resources; business disruption and crisis management; the impact on
our reputation of ethical misconduct and non-compliance with
regulatory obligations; trading losses; major uninsured losses;
decisions by Rosneft’s management and board of directors; the
actions of contractors; natural disasters and adverse weather
conditions; changes in public expectations and other changes to
business conditions; wars and acts of terrorism; cyber attacks or
sabotage; and other factors discussed elsewhere in this report
including under Risk factors (pages 57-58). 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.
278
«See Glossary
BP Annual Report and Form 20-F 2017
Shareholder
information
280 Share pricings and listings
280 Dividends
281 Shareholder taxation information
283 Major shareholders
284 Annual general meeting
284 Memoradum and Articles of Association
286
Purchases of equity securities by the issuer
and affiliated purchasers
287 Fees and charges payable by ADS holders
287 Fees and payments made by the Depositary to the issuer
287 Documents on display
288 Shareholding administration
288 Exhibits
S
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BP Annual Report and Form 20-F 2017
BP Annual Report and Form 20-F 2017
279
279
26_BP_AR_Financial_statements_contents_p115.indd 279
27/03/2018 10:39
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
2013
2014
2015
2016
2017
Year ended 31 December
2016: First quarter (January-March)
Second quarter (April-June)
Third quarter (July-September)
Fourth quarter (October-December)
2017: First quarter (January-March)
Second quarter (April-June)
Third quarter (July-September)
Fourth quarter (October-December)
2018: First quarter (to 8 March)
Month of
September 2017
October 2017
November 2017
December 2017
January 2018
February 2018
March 2018 (to 8 March)
High
494.20
526.80
487.50
513.24
529.00
381.80
438.15
464.40
513.24
521.20
479.39
480.60
529.00
536.20
480.60
522.21
529.00
523.50
536.20
519.10
477.65
Pence
Ordinary shares
Low
Dollars
American depositary sharesa
High
Low
426.50
364.40
319.90
309.10
436.95
309.10
335.07
408.63
432.15
440.80
437.68
436.95
477.10
452.50
440.00
477.10
488.05
482.65
500.40
452.50
463.90
48.65
53.48
43.85
37.68
42.23
32.38
35.59
37.28
37.68
38.68
37.19
38.48
42.23
44.62
38.48
40.97
41.55
42.23
44.62
43.65
39.80
39.99
34.88
29.35
27.01
33.10
27.01
28.67
32.50
32.53
33.10
33.83
33.90
37.98
36.15
34.26
37.98
38.75
39.22
41.81
36.15
38.33
a One ADS is equivalent to six 25 cent ordinary shares.
Source: FactSet for 2017 and 2018. Thomson Reuters Datastream for 2013-2016.
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 8 March 2018, 913,607,017.5 ADSs (equivalent to approximately
5,481,642,105 ordinary shares or some 27.50% of the total issued
share capital, excluding shares held in treasury) were outstanding and
were held by approximately 84,659 ADS holders. Of these, about
83,686 had registered addresses in the US at that date. One of the
registered holders of ADSs represents some 1,020,454 underlying
holders.
On 8 March 2018 there were approximately 242,521 ordinary
shareholders. Of these shareholders, around 1,575 had registered
addresses in the US and held a total of some 4,189,051 ordinary
shares.
Since a number of the ordinary shares and ADSs were held by
brokers and other nominees, the number of holders in the US may
not be representative of the number of beneficial holders of their
respective country of residence.
Dividends
BP’s current policy is to pay interim dividends on a quarterly basis on
its ordinary shares.
Its policy is also to announce dividends for ordinary shares in US
dollars and state an equivalent sterling dividend. Dividends on BP
ordinary shares will be paid in sterling and on BP ADSs in US dollars.
The rate of exchange used to determine the sterling amount
equivalent is the average of the market exchange rates in London
over the four business days prior to the sterling equivalent
announcement date. The directors may choose to declare dividends
in any currency provided that a sterling equivalent is announced. It is
not the company’s intention to change its current policy of
announcing dividends on ordinary shares in US dollars.
Information regarding dividends announced and paid by the company
on ordinary shares and preference shares is provided in Financial
statements – Note 8.
280
«See Glossary
BP Annual Report and Form 20-F 2017
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 is proposed that the Scrip Programme be renewed for a
further three years at the 2018 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 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 57 and other
matters that may affect the business of the group set out in Our
strategy on page 12 and in Liquidity and capital resources on page
251.
The following table shows dividends announced and paid by the
company per ADS for the past five years.
Dividends per ADSa
2013
2014
2015
UK pence
US cents
UK pence
US cents
UK pence
US cents
UK pence
US cents
2017 UK pence
US cents
2016
March
36.01
54
34.24
57
40.00
60
42.08
60
48.95
60
June September December
Total
35.01
54
34.84
58.5
39.18
60
41.50
60
46.54
60
34.58
54
35.76
58.5
39.29
60
45.35
60
45.73
60
34.80
57
38.26
60
39.81
60
47.59
60
44.66
60
140.40
219
143.10
234
158.28
240
176.52
240
185.88
240
a Dividends announced and paid by the company on ordinary and preference shares are
provided in Financial statements – Note 8.
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, was
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. From 6 April 2018 the
amount of the Dividend Allowance will fall to £2,000.
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
BP Annual Report and Form 20-F 2017
«See Glossary
281
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
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.
Under the Treaty, individuals who are residents of either the UK or the
US and who have been residents of the other jurisdiction (the US or
the UK, as the case may be) at any time during the six years
immediately preceding the relevant disposal of ordinary shares or
ADSs may be subject to tax with respect to capital gains arising from
a disposition of ordinary shares or ADSs of the company not only in
the jurisdiction of which the holder is resident at the time of the
disposition but also in the other jurisdiction.
US federal income taxation
A US holder who sells or otherwise disposes of ordinary shares or
ADSs will recognize a capital gain or loss for US federal income tax
purposes equal to the difference between the US dollar value of the
amount realized on the disposition and the US holder’s tax basis,
determined in US dollars, in the ordinary shares or ADSs. Any such
capital gain or loss generally will be long-term gain or loss, subject to
tax at a preferential rate for a non-corporate US holder, if the US
holder’s holding period for such ordinary shares or ADSs exceeds one
year.
Gain or loss from the sale or other disposition of ordinary shares or
ADSs will generally be income or loss from sources within the US for
foreign tax credit limitation purposes. The deductibility of capital
losses is subject to limitations.
We do not believe that ordinary shares or ADSs will be treated as
stock of a passive foreign investment company, or PFIC, for US
federal income tax purposes, but this conclusion is a factual
determination that is made annually and thus is subject to change. If
we are treated as a PFIC, unless a US holder elects to be taxed
annually on a mark-to-market basis with respect to ordinary shares or
ADSs, any gain realized on the sale or other disposition of ordinary
shares or ADSs would in general not be treated as capital gain.
Instead, a US holder would be treated as if he or she had realized
such gain rateably over the holding period for ordinary shares or ADSs
and would be taxed at the highest tax rate in effect for each such year
to which the gain was allocated, in addition to which an interest
charge in respect of the tax attributable to each such year would
apply. Certain ‘excess distributions’ would be similarly treated if we
were treated as a PFIC.
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.
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
282
«See Glossary
BP Annual Report and Form 20-F 2017
duty reserve tax will apply to agreements to transfer ordinary shares
even if the agreement is made outside the UK between two non-
residents. Purchases of ordinary shares outside the CREST system
are subject either to stamp duty at a rate of £5 per £1,000 (or part,
unless the stamp duty is less than £5, when no stamp duty is
charged), or stamp duty reserve tax at 0.5%. Stamp duty and stamp
duty reserve tax are generally the liability of the purchaser.
A subsequent transfer of ordinary shares to the Depositary’s nominee
will give rise to further stamp duty at the rate of £1.50 per £100 (or
part) or stamp duty reserve tax at the rate of 1.5% of the value of the
ordinary shares at the time of the transfer. For ADR holders electing
to receive ADSs instead of cash, after the 2012 first quarter dividend
payment, HM Revenue & Customs no longer seeks to impose 1.5%
stamp duty reserve tax on issues of UK shares and securities to non-
EU clearance services and depositary receipt systems.
US Medicare Tax
A US holder that is an individual or estate, or a trust that does not fall
into a special class of trusts that is exempt from such tax, is subject
to a 3.8% tax on the lesser of (1) the US holder’s ‘net investment
income’ (or ‘undistributed net investment income’ in the case of an
estate or trust) for the relevant taxable year and (2) the excess of the
US holder’s modified adjusted gross income for the taxable year over
a certain threshold (which in the case of individuals is between
$125,000 and $250,000, depending on the individual’s
circumstances). A holder’s net investment income generally includes
its dividend income and its net gains from the disposition of shares or
ADSs, unless such dividend income or net gains are derived in the
ordinary course of the conduct of a trade or business (other than a
trade or business that consists of certain passive or trading activities).
If you are a US holder that is an individual, estate or trust, you are
urged to consult your tax 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.
As at 31 December 2017 there were also 1,337 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 2017 BlackRock, Inc. held 6.51% and The Vanguard
Group, Inc. held 3.15% of the voting rights of the ordinary issued
share capital of the company. As at 8 March 2018 BlackRock, Inc.
held 6.65% and The Vanguard Group, Inc. held 3.21% of the voting
rights of the ordinary issued share capital of the company.
Under the US Securities Exchange Act of 1934 BP has received
notification of the following interests as at 8 March 2018:
Holder
JPMorgan Chase Bank N.A.,
depositary for ADSs, through
its nominee Guaranty
Nominees Limited
BlackRock, Inc.
Holding of
ordinary shares
Percentage of
ordinary share capital
excluding shares held
in treasury
5,481,642,105
1,325,269,035
27.50
6.65
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 8 March 2018:
Holder
The National Farmers Union Mutual
Insurance Society Limited
Hargreaves Lansdown Asset
Management Limited
Prudential plc
Barclays, plc
Holding of 8%
cumulative first
preference shares
Percentage
of class
945,000
13.07
534,146
528,150
385,996
7.39
7.30
5.34
Holder
Holding of 9%
cumulative second
preference shares
Percentage
of class
Register of members holding BP ordinary shares as at
31 December 2017
The National Farmers Union Mutual
Insurance Society Limited
Range of holdings
1-200
201-1,000
1,001-10,000
10,001-100,000
100,001-1,000,000
Over 1,000,000a
Totals
Number of
ordinary
shareholders
Percentage of
total
ordinary
shareholders
Percentage of
total
ordinary share
capital
excluding shares
held in treasury
53,742
82,932
94,138
10,976
887
658
243,333
22.09
34.08
38.69
4.51
0.36
0.27
100.00
0.01
0.23
1.49
1.14
1.66
95.47
100.00
a Includes JPMorgan Chase Bank, N.A. holding 27.71% 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.
Register of holders of American depositary shares (ADSs) as at
31 December 2017a
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
Percentage of
total ADS holders
Percentage of
total ADSs
50,511
22,533
11,894
569
9
1
85,517
59.07
26.35
13.91
0.67
0.00
0.00
100.00
0.30
1.17
3.36
1.02
0.16
93.99
100.00
a One ADS represents six 25 cent ordinary shares.
b One holder of ADSs represents 994,294 underlying shareholders.
Prudential plc
Interactive Investor Share Dealing
Services
Safra Group
Hargreaves Lansdown Asset
Management Limited
Barclays, plc
987,000
644,450
330,741
320,000
314,574
282,798
18.03
11.77
6.04
5.85
5.75
5.17
In accordance with DTR 5, 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.
BP Annual Report and Form 20-F 2017
«See Glossary
283
During 2016, 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 and increased above 5% on 14 November 2016.
During 2017, BlackRock Inc. notified the company that its indirect
interest in ordinary shares moved as follows: decreased below 5% on
9 February 2017; increased above 5% on 22 February 2017;
decreased below 5% on 8 May 2017; increased above 5% on 15 May
2017; increased above 5% on 14 August 2017; decreased below 5%
on 3 November 2017 and increased above 5% on 13 November 2017.
During 2018, BlackRock, Inc. notified the company that its indirect
interest in ordinary shares decreased below 5% on 12 February 2018.
As at 8 March 2018, the total preference shares in issue comprised
only 0.42% of the company’s total issued nominal share capital
(excluding shares held in treasury), the rest being ordinary shares.
Annual general meeting
The 2018 AGM will be held on Monday 21 May 2018 at 11.30am. 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.
The board appointed Deloitte LLP as the company's new auditor with
effect from 29 March 2018 to fill the vacancy arising from Ernst &
Young LLP's resignation following completion of their audit of BP’s
2017 financial statements. At the 2018 AGM, the board will seek
shareholder approval for the appointment of Deloitte LLP as the
company's auditor until the conclusion of the next AGM at which the
company's accounts are laid before shareholders.
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 287.
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. New Articles of Association are being proposed at the AGM
in 2018.
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.
• 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.
284
«See Glossary
BP Annual Report and Form 20-F 2017
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.
BP Annual Report and Form 20-F 2017
«See Glossary
285
Called-up share capital
Details of the allotted, called-up and fully-paid share capital at
31 December 2017 are set out in Financial statements – Note 29. At
the AGM on 17 May 2017, authorization was given to the directors to
allot shares up to an aggregate nominal amount equal to $3,260
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 $490 million (of which $245 million may
be used in respect of an acquisition or capital investment), without
having to offer such shares to existing shareholders. These authorities
were given for the period until the next AGM in 2018 or 17 August
2018, whichever is the earlier. These authorities are renewed annually
at the AGM.
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
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.
Purchases of equity securities by the issuer and affiliated purchasers
In November 2017 BP began a share repurchase or buyback programme (the programme). The sole purpose of the programme is to reduce the
issued share capital of the company to offset the ongoing dilutive effect of scrip dividends over time, as announced by the company on 31
October 2017. The period for which authorisation for the programme has been given is 15 November 2017 until the date of the company's 2018
annual general meeting (AGM). The maximum number of ordinary shares to be purchased will not exceed 1.96 billion ordinary shares, which is
the maximum number of ordinary shares permitted to be purchased by the company pursuant to the authority granted by shareholders at the
company's 2017 AGM . The shares purchased will be cancelled.
The following table provides details of ordinary share purchases made (1) under the programme and (2) 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.
2017
January
February 7
March
April 26
May 9
June
July
August 7 – August 11
September 1 – September 27
October
November 1 – November 30
December 5 – December 20
2018
January
February 6 – February 28
March 8
Nil
250,000
Nil
43,180
1,900,000
Nil
Nil
101,885
1,378,028
Nil
32,402,049
19,639,695
Nil
12,574,000
1,000,000
Total number
of shares
purchaseda
Average price
paid per share
$
Number of
shares
purchased
by ESOPs or for
certain
employee
share-based
plansb
Number of
shares
purchased as
part of the
buyback
programmec
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
31,652,049
19,639,695
Maximun
approximate
dollar value of
shares yet to
be purchased
under the
programme
$ million
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
N/A
5.80
250,000
5.74
5.91
43,180
1,900,000
101,885
1,378,028
750,000
Nil
6.11
6.04
6.65
6.75
6.69
6.58
24,000
Nil
12,550,000
1,000,000
a All share purchases were of ordinary shares of 25 cents each and/or ADSs (each representing six ordinary shares) and were on/open market transactions.
b Transactions represent the purchase of ordinary shares by ESOPs and other purchases of ordinary shares and ADSs made to satisfy requirements of certain employee share-based payment
plans.
c The company announced its intent to commence the programme on 31 October 2017 and announced further details and commencement of the programme on 15 November 2017. At the
AGM on 17 May 2017, authorization was given to the company to repurchase up to 1.96 billion ordinary shares, for the period ending on the date of the AGM in 2018 or 17 August 2018,
whichever is the earlier. This authorization is renewed annually at the AGM. The total number of ordinary shares repurchased during 2017 under the programme was 51,291,744 at a cost of
$343 million (including fees and stamp duty) representing 0.26% of BP’s issued share capital excluding shares held in treasury on 31 December 2017. All ordinary shares repurchased in 2017
under the programme were cancelled in order to reduce BP’s issued share capital.
286
«See Glossary
BP Annual Report and Form 20-F 2017
Fees and charges payable by ADS 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
Depositary actions
Fee
Depositing or substituting the
underlying shares
Selling or exercising rights
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.
$5.00 per 100 ADSs (or portion thereof)
evidenced by the new ADSs delivered.
$5.00 per 100 ADSs (or portion thereof).
Withdrawing an underlying
share
Acceptance of ADSs surrendered for withdrawal of
deposited securities.
$5.00 for each 100 ADSs (or portion thereof)
evidenced by the ADSs surrendered.
Expenses of the Depositary
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).
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.
Dividend fees
ADS holders who receive a cash dividend are charged a
fee which BP uses to offset the costs associated with
administering the ADS programme.
$0.02 per BP ADS per calendar year (equivalent
to $0.005 per BP ADS per quarter per cash
distribution).
Global Invest Direct (“GID”)
Plan
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.
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.
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 2017. The Depositary reimbursed to the
company, or paid amounts on the company’s behalf to third parties, or
waived its fees and expenses, of $16,175,185.26 for the year ended
31 December 2017.
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 2017.
Category of expense reimbursed,
waived or paid directly to third parties
Amount reimbursed, waived or
paid directly to third parties for the
year ended 31 December 2017
$
Fees for delivery and surrender of BP
ADSs
Dividend feesa
Total
712,698.23
15,462,487.03
16,175,185.26
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 2017 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 275) significant ways (if any)
in which its corporate governance practices differ from those
mandated for US companies under NYSE listing standards.
BP Annual Report and Form 20-F 2017
«See Glossary
287
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, Link 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
2018 shareholder calendara
29 Mar 2018
Fourth quarter interim dividend payment for 2017
1 May 2018
First quarter results announced
11 May 2018 Record date (to be eligible for the first quarter
interim dividend)
21 May 2018 Annual general meeting
22 Jun 2018
First quarter interim dividend payment for 2018
6 Jul 2018
8% and 9% preference shares record date
31 Jul 2018
Second quarter results announced
31 Jul 2018
8% and 9% preference shares dividend payment
10 Aug 2018
21 Sep 2018
Record date (to be eligible for the second quarter
interim dividend)
Second quarter interim dividend payment for 2018
30 Oct 2018
Third quarter results announced
9 Nov 2018
Record date (to be eligible for the third quarter
interim dividend)
21 Dec 2018
Third quarter interim dividend payment for 2018
a All future dates are provisional and may be subject to change. For the full calendar see
bp.com/financialcalendar.
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 4.3
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
Exhibit 15.6
Memorandum and Articles of Association
of BP p.l.c.*******†
The BP Executive Directors’ Incentive
Plan******†
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 35 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*******†
Letter of Ernst & Young LLP dated 29
March 2018 pursuant to Item 16F of Form
20-F†
Exhibit 101
Interactive data files
*
**
***
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 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.
288
«See Glossary
BP Annual Report and Form 20-F 2017
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.
MteCO2
Million tonnes of CO2 equivalent.
MW
Megawatt.
NGLs
Natural gas liquids.
PSA
Production-sharing agreement.
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.
Non-GAAP measures are sometimes referred to as alternative
performance measures.
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. A reconciliation to GAAP information is provided
on page 294.
We are unable to present reconciliations of forward-looking
information for adjusted ETR to ETR on profit or loss for the period,
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 the taxation on inventory holding gains and losses, non-
operating items and fair value accounting effects, that are difficult to
predict in advance in order to include in a GAAP estimate.
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
Total cash capital expenditure as stated in the group cash flow
statement.
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
26 and in Downstream on page 32. 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
BP Annual Report and Form 20-F 2017
289
pricing differences between locations, time periods and arbitrage
between markets.
Divestment proceeds
Disposal proceeds as per the group cash flow statement.
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. A reconciliation to GAAP
information is provided on page 294.
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
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. A
reconciliation to GAAP information is provided on page 294.
290
BP Annual Report and Form 20-F 2017
Free cash flow
Operating cash flow less net cash used in investing activities, as
presented in the group cash flow statement.
LNG train
An LNG train is a processing facility used to liquefy and purify natural
gas in the formation of LNG.
Full dividend
Full dividend is cash dividend plus cash equivalent value of scrip
dividend.
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.
Gearing
See Net debt and net debt ratio definition.
Gross debt ratio
Gross debt ratio is defined as the ratio of gross debt to the total of
gross debt plus shareholders' equity.
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 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 a cash 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. An analysis of organic capital
expenditure by segment and region, and a reconciliation to GAAP
information is provided on page 248.
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.
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 25 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 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 250.
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 Gulf of Mexico oil spill payments
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
net cash provided by operating activities excluding amounts related to
the Gulf of Mexico oil spill is a useful measure as it allows for more
meaningful comparisons between reporting periods. The nearest
equivalent measure on an IFRS basis is net cash provided by
operating activities. Organic free cash flow is operating cash flow
excluding Gulf of Mexico oil spill payments less organic capital
expenditure.
Operating cash margin – Upstream
Operating cash margin is operating cash flow divided by the
applicable number of barrels of oil equivalent produced, at $52/bbl flat
oil prices. Expected operating cash margins are calculated over the
period 2016-2025.
BP Annual Report and Form 20-F 2017
291
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 and is a non-GAAP measure. Organic
capital expenditure comprises capital expenditure 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 organic capital expenditure by segment and
region, and a reconciliation to GAAP information is provided on page
248.
We are unable to present reconciliations of forward-looking
information for organic capital expenditure to total cash capital
expenditure, because without unreasonable efforts, we are unable to
forecast accurately the adjusting item, inorganic capital expenditure,
that is difficult to predict in advance in order to derive the nearest
GAAP estimate.
Organic sources of cash and organic uses of cash
Non-GAAP measure. Organic sources of cash is the sum of operating
cash flow, excluding Gulf of Mexico oil spill payments, and proceeds
of loan repayments. Organic uses of cash is the sum of organic
capital expenditure, dividends and share buybacks. Organic sources
of cash and organic uses of cash are referred to as organic cash
flows which is also a non-GAAP measure. The nearest equivalent
measure on an IFRS basis for organic sources of cash is net cash
provided by operating activities and the nearest equivalent measures
on an IFRS basis for organic uses of cash are total cash capital
expenditure, dividends paid to BP shareholders and net issue
(repurchase) of shares.
Production-sharing agreement (PSA) / Production-sharing
contract
An arrangement through which an oil and gas 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.
Readily marketable inventory (RMI)
RMI is inventory held and price risk-managed by our integrated supply
and trading function (IST) which could be sold to generate funds if
required. It comprises oil and oil products for which liquid markets are
available and excludes inventory which is required to meet operational
requirements and other inventory which is not price risk-managed.
RMI is reported at fair value. Inventory held by the Downstream fuels
business for the purpose of sales and marketing, and all inventories
relating to the lubricants and petrochemicals businesses, are not
included in RMI. BP believes that disclosing the amounts of RMI and
paid-up RMI is useful to investors as it enables them to better
understand and evaluate the group’s inventories and liquidity position
by enabling them to see the level of discretionary inventory held by
IST and to see builds or releases of liquid trading inventory.
Paid-up RMI excludes RMI which has not yet been paid for. For
inventory that is held in storage, a first-in first-out (FIFO) approach is
used to determine whether inventory has been paid for or not. Unpaid
RMI is RMI which has not yet been paid for by BP. RMI, RMI at fair
value, Paid-up RMI and Unpaid RMI are non-GAAP measures. A
reconciliation of total inventory as reported on the group balance
sheet to paid-up RMI is provided on page 296.
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.
Refining net cash margin per barrel
Refining 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.
Refinery utilization
Refinery utilization is calculated as annual throughput (thousands of
barrels per day) divided by crude distillation capacity.
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 4. A reconciliation to
GAAP information is provided on page 248.
RC profit or loss per share
Non-GAAP measure. Earnings per share is defined in Financial
statements – Note 9. 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.
A reconciliation to GAAP information is provided on page 294.
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.
292
BP Annual Report and Form 20-F 2017
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. Interest expense is finance costs excluding
the unwinding of the discount on provisions and other payables. 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 295.
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, costly
damage to equipment or exceeding defined quantities. 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.
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.
Underlying RC profit or loss
Non-GAAP measure. RC profit or loss after adjusting for non-
operating items and fair value accounting effects. See page 250 and
294 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. Underlying profit in the group chief
executive’s letter on page 8 refers to full year underlying RC profit for
the group. A reconciliation to GAAP information is provided on page
248.
Underlying RC profit or loss per share
Non-GAAP measure. Earnings per share is defined Financial
statements – Note 9. 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. A reconciliation to GAAP information is provided on
page 294.
Upstream operating efficiency
Upstream operating efficiency is calculated as production for BP
operated sites, excluding US Lower 48 and adjusted for certain items
including entitlement impacts in our production-sharing agreements
divided by installed production capacity for BP operated sites,
excluding US Lower 48. Installed production capacity is the agreed
rate achievable (measured at the export end of the system) when the
installed production system (reservoir, wells, plant and export) is fully
optimized and operated at full rate with no planned or unplanned
deferrals.
Upstream plant reliability
BP-operated Upstream 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, which does not include Gulf of Mexico weather related
downtime.
Upstream unit production cost
Upstream unit production cost is calculated as production cost
divided by units of production. Production cost does not include ad
valorem and severance taxes. Units of production are barrels for
liquids and thousands of cubic feet for gas. Amounts disclosed are for
BP subsidiaries only and do not include BP’s share of equity-
accounted entities.
West Texas Intermediate (WTI)
A light sweet crude oil, priced at Cushing, Oklahoma, which serves as
a benchmark price for purchases of oil in the US.
Trade marks
Trade marks of the BP group appear throughout this report. They
include: ACTIVE, ampm, Aral, ARCO, BP, BP Fleetmove, BPme, BP
Ultimate, Castrol, EDGE BIO-SYNTHETIC, PTAir
Trade marks:
Amazon Web Services is a registered trade mark of Amazon
Technologies, Inc.
Butamax is a registered trade mark of Butamax Advance Biofuels
LLC.
DrillPlan is a registered trade mark of Schlumberger Technology
Corporation.
M&S Simply Food is a registered trade mark of Marks & Spencer plc.
Microsoft Azure a registered trade mark of Microsoft Corporation.
Nectar is a registered trade mark of Aimia US Inc.
PAYBACK is a registered trade mark of PAYBACK GmbH.
Pick n Pay is a registered trade mark of Pick n Pay Stores Limited.
REWE to go is a registered trade mark of REWE.
BP Annual Report and Form 20-F 2017
293
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 290.
Upstream
Unrecognized (gains) losses brought forward from previous perioda
Favourable (adverse) 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 (adverse) impact relative to management’s measure of performance
Unrecognized (gains) losses carried forward
Favourable (adverse) impact relative to management’s measure of performance – by region
Upstream
US
Non-US
Downstreamb
US
Non-US
Taxation credit (charge)
2017
2016
$ million
2015
(393)
27
2
(364)
(71)
(135)
(206)
192
(165)
27
(29)
(106)
(135)
(108)
12
(96)
263
(637)
(19)
(393)
377
(448)
(71)
(379)
(258)
(637)
(321)
(127)
(448)
(1,085)
329
(756)
191
105
—
296
188
156
344
(66)
171
105
102
54
156
261
(56)
205
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
2017
2016
5,194
27
5,221
7,356
(135)
7,221
9,582
(108)
9,474
1,211
(637)
574
5,610
(448)
5,162
655
(1,085)
(430)
$ million
2015
(1,042)
105
(937)
6,955
156
7,111
(8,179)
261
(7,918)
Reconciliation of basic earnings per ordinary share to RC profit (loss) per share and to underlying RC profit
per share
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) adverse 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.
2017
17.20
(4.32)
1.14
14.02
2016
0.61
(8.52)
2.58
(5.33)
2015
(35.39)
10.31
(3.10)
(28.18)
Per ordinary share – cents
2014
20.55
33.78
(10.43)
43.90
2013
123.87
1.53
(0.32)
125.08
18.94
35.99
82.23
44.79
(48.83)
(1.65)
31.31
(16.87)
13.79
(21.83)
32.22
(22.69)
66.00
(5.33)
70.92
294
«See Glossary
BP Annual Report and Form 20-F 2017
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 US tax reform
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 US tax reform
Adjusted for the impact of the reduction in the rate of the UK North
Sea supplementary charge
Adjusted ETR
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 (2017 average $159,389 million)
Less: Goodwill
Cash and cash equivalents
Average capital employed excluding goodwill and cash and cash
equivalents
ROACE
a Calculated on a post-tax basis using a notional tax rate of 35%.
2017
(3,712)
(225)
(3,487)
1,184
(859)
—
(3,812)
2017
52
3
55
(9)
(8)
—
38
2016
2,467
(483)
2,950
3,162
—
434
(646)
2016
107
(31)
76
(69)
—
16
23
2015
3,171
569
2,602
4,000
—
915
2014
(947)
1,917
(2,864)
$ million
2013
(6,463)
60
(6,523)
4,171
1,009
—
—
—
—
(2,313)
(7,035)
(7,532)
2015
33
1
34
(15)
—
12
31
2014
19
7
26
10
—
—
36
2017
2016
2015
3,389
(628)
3,405
6,166
924
79
7,169
100,404
63,230
163,634
11,551
25,586
126,497
115
(1,114)
3,584
2,585
635
57
3,277
96,843
58,300
155,143
11,194
23,484
120,465
(6,482)
1,320
11,067
5,905
576
82
6,563
98,387
53,168
151,555
11,627
26,389
113,539
2014
3,780
4,293
4,063
12,136
546
223
12,905
112,642
52,854
165,496
11,868
29,763
123,865
123,481
117,002
118,702
133,882
140,313
5.8%
2.8%
5.5%
9.6%
10.2%
%
2013
21
—
21
14
—
—
35
$ million
2013
23,451
230
(10,253)
13,428
549
307
14,284
130,407
48,192
178,599
12,181
22,520
143,898
BP Annual Report and Form 20-F 2017
«See Glossary
295
Readily marketable inventory (RMI)
Readily marketable inventory (RMI) is oil and oil products inventory held and price risk-managed by BP`s integrated supply and trading function
(IST) which could be sold to generate funds if required. Details of RMI balances and a reconciliation to GAAP information is set out below.
Further information on RMI, RMI at fair value, paid-up RMI and unpaid RMI is provided on page 292.
At 31 December
RMI at fair value
Paid-up RMI
Reconciliation of non-GAAP information
At 31 December
Reconciliation of total inventory to paid-up RMI
Inventories as reported on the group balance sheet
Less: (a) inventories which are not oil and oil products and (b) oil and oil product inventories which are not risk-
managed by IST
RMI on IFRS basis
Plus: difference between RMI at fair value and RMI on an IFRS basis
RMI at fair value
Less: unpaid RMI at fair value
Paid-up RMI
2017
5,661
2,688
$ million
2016
5,952
2,705
2017
$ million
2016
19,011
17,655
(13,929)
(12,131)
5,082
579
5,661
(2,973)
2,688
5,524
428
5,952
(3,247)
2,705
The Directors’ report on pages 59-89, 113-114, 191-218 and 247-296 was approved by the board and signed on its behalf by David J Jackson,
company secretary on 29 March 2018.
BP p.l.c.
Registered in England and Wales No. 102498
296
«See Glossary
BP Annual Report and Form 20-F 2017
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
29 March 2018
BP Annual Report and Form 20-F 2017
297
Cross reference to Form 20-F
A.
B.
C.
D.
A.
B.
C.
D.
A.
B.
C.
D.
E.
F.
G.
A.
B.
C.
D.
E.
A.
B.
C.
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
Page
n/a
n/a
248
n/a
n/a
57-58
History and development of the company
2-3, 21-43, 143-150, 155, 158-160, 251-252, 253-257, 265, 270-274, 284, 299
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
2-9, 10-19, 20-43, 135, 147-150, 251, 253-258, 265-270
184, 299
17, 24, 30, 40, 155, 169-170, 216-218, 253-258, 261-262, 274
None
18-19, 21-43, 57-58, 126, 129, 130-144, 147-150, 158-160, 168, 170-176, 251, 265-270,
273-274
21-22, 25, 128-129, 136, 155, 168-173, 213-215, 251-252
10, 23, 24, 44-46, 49, 150
10-11, 20-25, 29, 34
169-170, 251-252
252
277-278
60-69, 73
18-19, 90-112, 182
60-65, 70-89,182
53-54, 183
54, 90-112, 183
283-284
158-160, 274
n/a
Consolidated statements and other financial information
123-190, 251, 270-273, 280-281
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
n/a
280
n/a
280
n/a
n/a
n/a
n/a
284-286
274
281
281-283
n/a
n/a
287
n/a
170-176
n/a
n/a
n/a
287
None
None
123-124, 275-276
64-65, 77, 275
275
82, 183, 276
None
286
82-83
275
n/a
125-129
288
298
BP Annual Report and Form 20-F 2017
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:
BP America Inc.
501 Westlake Park Boulevard
Houston, Texas 77079
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 2017. A cross reference to Form 20-F requirements
is included on page 298.
This document contains the Strategic report on the inside front cover and pages 1-58 and the
Directors’ report on pages 59-89, 113-114, 191-218 and 247-296. 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 90-112. The consolidated financial statements of the group are
on pages 115-190 and the corresponding reports of the auditor are on pages 116-124. The parent
company financial statements of BP p.l.c. are on pages 219-245.
The Directors’ statements (comprising the Statement of directors’ responsibilities; Risk
management and internal control; Longer-term viability; Going concern; 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 and a non-GAAP measure of operating cash flow excluding Gulf of Mexico oil
spill payments in the tables on pages 18, 21, 22 and 25 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 2017 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
2017, 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, Advancing the energy
transition, 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 280 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.
Acknowledgements
Design: SALTERBAXTER MSLGROUP
Typesetting: BP and Donnelley Financial Solutions
Printing: Pureprint Group Limited, UK, ISO 14001, FSC® certified and CarbonNeutral®
Photography: Aaron Tait, Bård Gudim, Bob Wheeler, Christian Sprogoe, Graham Trott, Joshua
Drake, Marc Morrison, Mehmet Binay, Richard Davies, Simon Kreitem, Stuart Conway
Paper: This document is printed on Oxygen paper and board. Oxygen is made using 100%
recycled pulp, a large percentage of which is de-inked. It is manufactured at a mill with ISO 9001
and 14001 accreditation and is FSC® (Forest Stewardship Council) certified. This document has
been printed using vegetable inks.
BP Annual Report and Form 20-F 2017
«See Glossary
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